<PAGE>   1
                     SECURITIES AND EXCHANGE COMMISSION
                           Washington, D.C. 20549
                                  FORM 10-K

[X]  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
     EXCHANGE ACT OF 1934

                                       OR

[ ]  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
     EXCHANGE ACT OF 1934 [NO FEE REQUIRED]

For the fiscal year ended December 31, 1997       Commission File Number 0-18886

                               HS RESOURCES, INC.
              -----------------------------------------------------
             (Exact name of Registrant as specified in its charter)


        DELAWARE                                           94-3036864
-------------------------------                        -------------------
(State or other jurisdiction of                         (I.R.S. Employer
incorporation or organization)                         Identification No.)


ONE MARITIME PLAZA, FIFTEENTH FLOOR
SAN FRANCISCO, CA                                             94111
---------------------------------------                     ----------
(Address of principal executive offices)                    (Zip Code)

Registrant's telephone number, including area code:  (415) 433-5795

           SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT

<TABLE>
<CAPTION>
Title of each class of stock
----------------------------
<S>                                                  <C>
Common Stock - $.001 par value                       New York Stock Exchange
</TABLE>

      SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:  NONE

Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.  Yes  X  No
                                               ---    ---

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy information statements
incorporated by reference in Part III of the Form 10-K or any amendment to this
Form 10-K.  [X]

Aggregate market value of Common Stock held by non-affiliates of the registrant
as of the close of business at February 28, 1998:  $241,268,664.

Number of shares of Common Stock outstanding as of the close of business on
February 28, 1998: 18,423,987 after deducting 230,558 shares in treasury.

                      DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the Proxy Statement of HS Resources, Inc. to be dated on or before
April 30, 1998, are incorporated by reference into Part III.  (A definitive
proxy statement will be filed with the Commission within the prescribed
period.)
<PAGE>   2

                               TABLE OF CONTENTS


<TABLE>
<CAPTION>
                                                                                                  Page
                                                                                                  ----
<S>                       <C>                                                                       <C>
Part I.

         Item 1.          Business  . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .      3
         Item 2.          Properties  . . . . . . . . . . . . . . . . . . . . . . . . . . . . .     11
         Item 3.          Legal Proceedings and Environmental Issues  . . . . . . . . . . . . .     20
         Item 4.          Submission of Matters to a Vote of Security Holders . . . . . . . . .     21

Part II.

         Item 5.          Market for Registrant's Common Equity and Related
                              Stockholder Matters . . . . . . . . . . . . . . . . . . . . . . .     22
         Item 6.          Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . .     23
         Item 7.          Management's Discussion and Analysis of Financial
                              Condition and Results of Operations . . . . . . . . . . . . . . .     24
         Item 8.          Financial Statements and Supplementary Data . . . . . . . . . . . . .     42
         Item 9.          Changes in and Disagreements with Accountants on
                              Accounting and Financial Disclosure . . . . . . . . . . . . . . .     74

Part III.

         Items 10-13.           . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .     74

Part IV.

         Item 14.         Exhibits  . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .     75
</TABLE>




                                       2
<PAGE>   3

                                     PART I

Item 1.          BUSINESS

THE COMPANY

HS Resources, Inc. ("HSR" or the "Company") is a leading U.S. independent energy
company engaged in the acquisition, development, exploitation, exploration,
production and marketing of oil and gas. In 1997 HSR established Company records
in production and reserves, both on an absolute and a per-share basis.
Production for the year was 2.4 million barrels of oil and 41 billion cubic feet
of gas, or 9.3 million barrels of oil equivalent ("Boe"), an increase of 21%
over 1996. Year end proved reserves were 45.4 million barrels of oil and 880
billion cubic feet of gas, or 192 million Boe, an increase of 35% over the prior
year. Reserves per share were 10.9 Boe, an increase of 12% over the prior year,
and production per share was 0.53 Boe, compared to 0.52 Boe in 1996.

In December 1997, HSR acquired from Amoco Production Company ("Amoco") all of
Amoco's producing and non-producing properties (the "Amoco Properties") in the
Wattenberg Field area of the Denver-Julesburg ("D-J") Basin (the "Amoco
Acquisition"). This strategic acquisition positions HSR as the leading producer
in the D-J Basin with estimated daily production at year end of more than 25.1
MBoe. The Amoco Properties have substantial geographic and geological overlap
with HSR's existing D-J Basin assets and provide the Company with more than
2,100 low-risk, high-return projects, many of which can be undertaken with a
significantly lower capital investment than that which would have been required
for development by HSR or Amoco independently. The Amoco Properties present the
Company with almost $500 million of development and exploitation capital
expenditure opportunities that greatly enhance its reserve and production growth
potential.

The Company has created a diversified asset base with activities in four core
geographic areas: the D-J Basin, the Mid-Continent, the onshore area of the
Texas-Louisiana Gulf Coast and the Northern Rocky Mountains. The Company's
Mid-Continent presence, which is focused in the Anadarko and Arkoma Basins, was
established through its 1996 merger (the "Merger") with Tide West Oil Company
("Tide West"). This presence has been further enhanced by exploration,
exploitation and development activities. The Company has current daily
production from its Mid-Continent properties of 32,689 Mcf of gas and 1,016 Bbl
of oil. In the Gulf Coast, the Company has assembled control of approximately
335,000 gross undeveloped acres and is conducting an active exploration and
drilling program. The Company has acquired more than 530 square miles of 3-D
seismic data. In the Northern Rocky Mountains, the Company has 593,000 gross
undeveloped acres, primarily in the Williston and Greater Green River Basins.

At year end, HSR had an inventory of over 4,100 development, exploitation and
exploration opportunities, along with over 1.2 million gross undeveloped acres.
The opportunities include development, exploitation, exploration and infill
drilling, recompletion, wellbore deepening and refracturing projects. The
Company believes that each of its four core geographic areas presents
opportunities for growth in proved reserves and production.

At December 31, 1997, the Company reported proved reserves of 192 MMBoe, with
estimated pre-tax present value (discounted at 10%) of $822.5 million. Gas
constituted approximately 76% of the Company's reserves and approximately 67% of
the Company's reserves were classified as



                                       3
<PAGE>   4
developed. At December 31, 1997, the Company operated approximately 62% of its
5,375 wells. During the twelve months ended December 31, 1997 the Company
generated net cash flow (defined as net income, plus depreciation, depletion and
amortization, deferred taxes and extraordinary items) of $70.7 million, with
average production for the quarter ended December 31, 1997 of 26,277 Boe per
day.

HSR is a Delaware corporation organized in 1987. Its principal subsidiaries are
Orion Acquisition, Inc. ("Orion"), which holds the assets acquired in the Basin
Acquisition, HSRTW, Inc. ("HSRTW"), which holds the assets acquired through the
Merger, and HS Energy Services, Inc. ("HSES"), the Company's gas marketing,
trading and transportation subsidiary. The Company's principal executive offices
are located at One Maritime Plaza, Fifteenth Floor, San Francisco, California
94111 and its telephone number at such address is (415) 433-5795.





                                       4
<PAGE>   5
BUSINESS STRATEGY

HSR's objective is to maximize shareholder value through aggressive growth in
its oil and gas reserves and production. To achieve these objectives, the
Company pursues a strategy of (i) consolidation in core areas, (ii) exploitation
of its property base, (iii) exploration in focused prospective areas, and (iv)
application of advanced technology.

          o  Consolidation. Near the end of 1997 HSR acquired Amoco's D-J Basin
             properties, capping an effort that spanned several years. For HSR,
             the compelling reason for the acquisition was the substantial
             reserves that could be unlocked by combining the Amoco properties
             with its own. For example, in many instances HSR owns the right to
             produce from formations which are "behind pipe" in an Amoco
             producing well. Bringing these reserves into production by
             recompleting an existing well generates substantially better
             economics than can be achieved by drilling a new well. In other
             instances, Amoco owned the right to produce from formations located
             deeper than horizons from which HSR was already producing.
             Deepening an existing well is substantially more economic than
             drilling a new well. Without these efficiencies many reserves were
             economically "stranded" because drilling a new well could not be
             justified. The re-aggregation of reserves and value created by the
             Amoco Acquisition gives the Company a substantial inventory of
             projects with little operational risk, but with attractive rates of
             return.

          o  Exploitation. HSR has more than 4,100 low risk exploitation
             projects in its inventory, including such activities as
             recompleting new formations in existing wells, re-stimulating
             currently producing zones, deepening existing wells to new
             formations, and drilling infill and other development locations.
             Located primarily in the D-J Basin and the Mid-Continent region,
             these projects show attractive rates of return. Based on its
             planned exploitation program alone, without taking into
             consideration exploration success, the Company believes it should
             be able to sustain substantial production growth for the next five
             years. The Company anticipates a total 1998 capital budget of
             $90-$100 million, with $60-$75 million allocated to the D-J Basin
             and $15-$20 million allocated to the Mid-Continent for low risk
             exploitation projects. In the D-J Basin the Company plans to
             undertake more than 550 exploitation activities in 1998, drilling
             90 new wells, including 55 J-Sand infills, 436 recompletions and
             refracs and 40 Dakota deepenings. In the Mid-Continent the Company
             plans to drill 73 wells and recomplete 12. In addition, to
             replenish its inventory the Company has several ongoing initiatives
             including further reservoir analyses in the D-J Basin and active
             exploitation teams focused on the Arkoma and Anadarko Basins in the
             Mid-Continent.

          o  Exploration. HSR has 22 high-potential exploration projects in
             various stages of maturity and development. Eighteen active
             projects are located in the Gulf Coast region, where the Company
             has shot more than 530 square miles of 3-D seismic and has
             identified 110 prospects and leads. Initial geological and
             geophysical work is nearing completion on several of the projects,
             and the Company expects to spend net capital of approximately $15
             to $20 million in the Gulf Coast during 1998, drilling an
             anticipated 21 wells, shooting 285 square miles of 3-D seismic and
             acquiring leasehold and option acreage.





                                       5
<PAGE>   6
             HSR also has active exploration projects in the Mid-Continent
             region, the D-J Basin and in the Northern Rockies. The principal
             focus of the Mid-Continent District will be the 3-D program on the
             Company's Bivins Ranch field. 3-D driven exploration will continue
             in the D-J Basin. In addition, the Company's large acreage position
             in the Northern Rockies continues to yield significant
             opportunities. Joint programs with industry partners are under way
             on the Pinedale anticline and in the Williston Basin, and the
             Company has two high-potential projects in the Green River Basin in
             Wyoming.

          o  Technology. HSR's highest visibility technology is the use of 3-D
             seismic in its exploration programs. Use of this technology is
             intended to reduce exploratory risk and enhance economic results.
             The Company's 3-D seismic inventory includes 985 square miles of
             data coverage in hand and interpreted, with almost 400 square miles
             of additional seismic planned and under program design. Other
             technologies applied by the Company include reservoir simulators,
             directional drilling techniques and fully integrated digital
             databases, each of which aids in the efficient development of
             hydrocarbons. In addition, proprietary systems are used to enhance
             operating efficiencies by identifying and high-grading wells for
             field optimization, further engineering study and field remedial
             work. Other proprietary systems are planned or under development,
             including one intended to apply "artificial intelligence" methods
             to schedule field maintenance activity.


RECENT DEVELOPMENTS

Acquisitions and Divestitures

The Company is committed to strategic rationalization of assets in each of its
core areas both through advantageous acquisitions and non-core property
divestitures. The Company has aggressively pursued these objectives, resulting
in the Amoco Acquisition, three significant dispositions, several smaller
tactical acquisitions and the screening of numerous acquisition opportunities.
During 1997, the Company sold non-strategic, non-core properties (including the
assets transferred to Amoco as part of the Amoco Acquisition) in three
transactions for an aggregate of $58.6 million.

Amoco Acquisition

The Amoco Acquisition provides (i) a significant increase in oil and gas
production (adding net daily production at year end of 8,353 Boe from the Amoco
Properties), (ii) an expected reduction in per unit operating costs due in part
to increased production per wellbore following development and exploitation
activities, (iii) an anticipated increase in D-J Basin capital spending to
$60-75 million for 1998 to pursue additional infill, recompletion, deepening,
refrac and drilling projects, (iv) an expected decrease in per unit general and
administrative expense and (v) an increase of approximately $2.5 million per
year net to the Company in the monetization of Section 29 income tax credits.
The increase in production from the Amoco Properties is partially offset by the
estimated daily production at year end of 1,252 Boe from the properties
transferred to Amoco.




                                       6
<PAGE>   7

MARKETING AND TRADING

Gas Marketing and Trading

Since the beginning of 1996, the market for the Company's D-J Basin gas has
strengthened substantially due to several factors. First, excess supply from
Wyoming gas producers has declined as a result of increased demand from West
Coast markets. Second, in October 1995 the Colorado Public Utilities Commission
approved tariff changes that effectively eliminated transportation costs for D-J
Basin gas sold to the Colorado Front Range market, resulting in a transportation
cost advantage for D-J Basin producers of approximately $0.40 per MMBtu. Third,
the supply of D-J Basin gas has declined over the last two years due to the
combination of reduced drilling in the D-J Basin and natural production
declines. The Company's transportation cost advantage in the D-J Basin could be
reduced as a result of certain proposed pipeline projects. For further
discussion, see "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Gas Price Considerations." The market for the Company's
Mid-Continent gas remains stable and flexible with access to a number of
interstate pipelines.

Oil Marketing and Trading

Substantially all of the Company's oil production is sold under contracts having
terms of one year or less based on prices which are reflective of world crude
oil prices adjusted for geographic and quality differentials. Oil is sold to
many different purchasers at generally market sensitive rates. The most
significant purchaser of the Company's oil production currently is Amoco, which
purchases 39% of the Company's oil production. The Company believes that there
are sufficient crude oil purchasers in the market so that the loss of any one
particular customer would not have an adverse effect on the Company.

SECTION 29 TAX CREDITS

The Company and certain of its subsidiaries continue to enter into transactions
designed to monetize the Company's Section 29 tax credits. Through these
transactions, the Company has preserved a portion of the value of the Section 29
tax credits for production from tight gas sand reservoirs. That value would
otherwise be lost to the Company because of its tax position. In each
transaction, the Company or its subsidiary conveys substantially all of the
working interest in credit-qualified properties to a limited liability company
owned by one or more large financial institutions. The Company retains a 100%
production payment in the properties and an option to reacquire the properties.
The effect of the transactions is such that the Company receives
production-related cash flow as if it were the working interest owner, and the
investor receives tax credits. The investor makes an initial payment to the
Company, and makes periodic payments that vary depending on the volume of
credit-qualified gas produced. The transactions are structured in accordance
with private letter rulings issued by the Internal Revenue Service ("IRS") to
third parties. In some cases, the investors obtain private letter rulings which
specifically cover the Company's transactions. Through these transactions, the
Company has recognized approximately $4.4 million and $2.7 million of other gas
revenues associated with the tax credits during the years ended December 31,
1997 and 1996, respectively. The Company expects to receive in excess of $29
million of tax credits for the period 1998 through 2002.




                                       7
<PAGE>   8
Although the Company believes the possibility is remote, the IRS could decide to
challenge the validity of the transactions that are not directly protected by a
letter ruling.

COMPETITION

The oil and gas industry is highly competitive. The Company competes in the
areas of property acquisitions and the development, production and marketing of
oil and gas with major oil companies, other independent oil and gas concerns and
individual producers and operators. The Company also competes with major and
independent oil and gas concerns in recruiting and retaining qualified
employees. Many of these competitors have substantially greater financial and
other resources than the Company.

REGULATION

The following discussion of regulation of the oil and gas industry is
necessarily brief and is not intended to constitute a complete discussion of the
various statutes, rules, regulations or governmental orders to which operations
of the Company may be subject.

Price Controls on Liquid Hydrocarbons. There are currently no federal price
controls on oil production. There can be no assurance, however, that Congress
will not enact price controls in the future.

Federal Regulation of First Sales and Transportation of Gas. Historically, the
transportation and sale for resale of gas in interstate commerce have been
regulated pursuant to the Natural Gas Act ("NGA"), the Natural Gas Policy Act
("NGPA"), and the regulations promulgated thereunder by the Federal Energy
Regulatory Commission ("FERC"). Maximum selling prices of certain categories of
gas sold in "first sales," whether sold in interstate or intrastate commerce,
were regulated pursuant to the NGPA. On July 26, 1989, the Natural Gas Wellhead
Decontrol Act (the "Decontrol Act") was enacted removing, as of January 1, 1993,
all remaining federal price controls from gas sold in "first sales." The FERC's
jurisdiction over gas transportation was unaffected by the Decontrol Act.

Commencing in the mid-1980s and continuing until the present, the FERC
promulgated a series of orders designed to correct market distortions and to
make gas markets more competitive by, among other things, removing the
transportation barriers to market access. These orders have had a significant
impact upon gas markets in the United States and have, among other things,
fostered the development of a large spot market for gas and increased
competition for gas markets. As a result of the FERC orders, producers have
direct access to gas markets but face increased competition for those markets
and must operate under complex transportation tariffs in order to take advantage
of the opportunity to directly access gas markets.

Interstate pipelines continue to be regulated by the FERC under the NGA. Various
state commissions also regulate the rates and services of pipelines whose
operations are purely intrastate in nature. Some state utility commissions,
including the Colorado Public Utilities Commission, now require that state
pipeline and local distribution public utilities offer open access,
non-discriminatory transportation which allows consumers connected to those
systems to contract with producers or other suppliers for gas.




                                       8
<PAGE>   9
State and Local Regulation of Drilling and Production. State regulatory
authorities have established rules and regulations governing, among other
things, permits for drilling and production, drilling and operations,
performance bonds, reports concerning operations, discharge, disposal and other
waste-related permits, well spacing, unitization and pooling of operations and
taxation. The states in which the Company operates have enacted statutes and
regulations governing a number of environmental and conservation matters,
including the unitization or pooling of oil and gas properties. A few states
also prorate production to the market demand for oil and gas. Some states have
also enacted statutes establishing maximum rates of production from oil and gas
wells.

Environmental Regulations. The Company's operations are subject to complex and
constantly changing environmental laws and regulations adopted by Federal, state
and local governmental authorities. Compliance with such laws has not had a
material adverse effect upon the Company to date and the Company is not aware of
any matter that is likely to have a material adverse effect on it in the future.
However, in May 1995, the Company was named as a respondent by the United States
Environmental Protection Agency ("EPA") in an administrative order brought under
the Resource Conservation and Recovery Act ("RCRA") by the EPA against a
third-party owner/operator of an oilfield production water evaporation facility.
The Company does not believe that its share of reclamation costs will have a
material impact on its financial position or results of operations. See Item 3.
"Legal Proceedings--Environmental Issues," and Note 10 to Consolidated Financial
Statements. Also, the discharge of oil, gas or other pollutants into the air,
soil or water may give rise to significant liabilities of the Company to the
government and/or third parties. Presently, the State of Colorado Oil and Gas
Commission is considering adopting stricter policies for the enforcement of
environmental rules and regulations. Moreover, the Company has agreed to
indemnify certain sellers of producing properties from whom the Company has
acquired properties against certain liabilities for environmental claims
associated with the properties purchased by the Company. No assurance can be
given that existing environmental laws or regulations, as currently interpreted
or as may be interpreted in the future, or future laws, regulations and policies
will not materially adversely affect the Company's results of operations and
financial condition or that material indemnity claims will not arise against the
Company with respect to properties acquired by the Company.

Federal Leases. Operations on federal leases must be conducted in accordance
with permits and regulations issued by the Bureau of Land Management or other
federal agencies and are subject to a number of other regulatory restrictions.
Moreover, on certain federal leases, prior approval of drillsite operations must
be obtained from the EPA.

TITLE TO PROPERTIES

A title opinion generally is obtained prior to the commencement of drilling
operations on properties. The Company has obtained title opinions on
substantially all of its producing properties and believes that it has
satisfactory title to such properties in accordance with standards generally
accepted in the oil and gas industry. The Company's properties are subject to
customary royalty interests, liens for current taxes and other burdens which the
Company believes do not materially interfere with the use or affect the value of
such properties. A portion of the Company's oil and gas properties are mortgaged
to secure borrowings under the Company's credit facilities. Title investigation
before acquiring undeveloped properties is typically thorough but less rigorous
than that conducted prior to drilling, consistent with standard industry
practice.







                                       9
<PAGE>   10

OPERATIONAL HAZARDS AND INSURANCE

The Company's operations are subject to the usual hazards incident to the
drilling and production of oil and gas, such as blowouts, cratering, explosions,
uncontrollable flows of oil, gas or well fluids, fires, pollution, releases of
toxic gas and other environmental hazards and risks. These hazards can cause
personal injury and loss of life, severe damage to and destruction of property
and equipment, pollution or environmental damage and suspension of operations.

The Company has engaged Aon Risk Services, one of the world's largest insurance
brokerage firms, to maintain various types of coverage for its operations. The
Company believes its insurance coverage is reasonable and prudent for the types
of risks it expects to encounter. The Company's insurance does not cover every
potential risk associated with the drilling, production, storage and
transportation of oil and gas and, while certain environmental coverage is
provided, coverage is not obtainable for all types of environmental hazards. The
occurrence of a significant adverse event, the risks of which are not fully
covered by insurance, could have a material adverse effect on the Company's
financial condition and results of operations. Moreover, no assurance can be
given that the Company will be able to maintain adequate insurance in the future
at rates it considers to be reasonable.

EMPLOYEES

At December 31, 1997, the Company had 260 employees, with 30 located in San
Francisco, California, 74 in Denver, Colorado, 68 in Tulsa, Oklahoma, 86 in
Evans, Colorado and 2 in Houston, Texas. None of the Company's employees are
subject to a collective bargaining agreement. The Company considers its
relations with its employees to be good. The Company anticipates that it will
hire additional personnel consistent with its current development drilling
programs and other activities.

OFFICES

The Company leases its headquarters office at One Maritime Plaza, Fifteenth
Floor, San Francisco, California under a lease currently covering 20,548 square
feet expiring in December 2003, at an average monthly rental of $35,753. In
1997, the Company entered into a new six year lease, with options, in Denver,
Colorado which covers 52,749 square feet at an average monthly rental of
$59,098. In August 1997, the Company entered into a lease agreement for 5,362
square feet of office space in Houston, Texas, at a monthly cost of $4,692,
expiring April 30, 2000. The Company leases office space in Tulsa, Oklahoma
which covers 24,581 square feet at a monthly rental of $29,768 per month
expiring December 31, 2001. The Company also leases a field office in Evans,
Colorado consisting of 7,900 square feet of office space and 2,200 square feet
of warehouse space for $6,605 per month expiring April 9, 2002.







                                       10
<PAGE>   11

Item 2.          PROPERTIES

OIL AND GAS PROPERTIES

         The following table summarizes certain information with respect to each
of the Company's areas of operations and production. All information is
presented as of December 31, 1997.


<TABLE>
<CAPTION>
                                                          RESERVES                                                           3-D
                             --------------------------------------------------------------                                SEISMIC
                             TOTAL                                       OIL     PERCENT OF      NET          GROSS          DATA
                             GROSS    PERCENT    OIL        GAS      EQUIVALENT    TOTAL       PRODUCTION    UNDEVELOPED   (SQUARE
                             WELLS    OPERATED  (MBBL)     (MMCF)      (MBOE)     RESERVES    (BOE/DAY)(1)   ACREAGE(2)     MILES)
                             -----    --------  ------     -------   ----------  ----------   ------------   -----------   -------
<S>                          <C>      <C>       <C>        <C>       <C>         <C>          <C>            <C>           <C>
D-J Basin
     Wattenberg Field Area   3,891       62     38,287     671,670     150,232       78           13,226       101,803        --
     Greater D-J Basin         495       92      2,130      37,852       8,439        4            4,965       173,333        84
Mid-Continent
     Anadarko Basin            405       37      1,581      48,055       9,590        5            3,315         1,520        13
     Arkoma Basin              384       56         47      62,646      10,488        6            1,866         6,052        --
     Southern Oklahoma          90       66      2,578      28,366       7,305        4            1,346           720        --
     New Mexico/Texas           75       51        537      24,740       4,660        3              858        25,570        24
Gulf Coast                       9       22         92       3,054         601       --              675       334,575       531
Northern Rocky Mountains        26       96        106       3,471         685       --               26       593,345       333
                             -----    -----     ------     -------     -------      ---           ------     ---------       ---

           Total:            5,375       62     45,358     879,854     192,000      100           26,277     1,236,918       985
                             =====    =====     ======     =======     =======      ===           ======     =========       ===
</TABLE>


(1) Calculated for the quarter ended December 31, 1997.

(2) Includes leasehold, option and seismic rights.


Denver-Julesburg Basin

The D-J Basin is located in northeastern Colorado, and for more than 15 years
has been the Company's primary producing region. HSR's D-J Basin production and
reserves are largely found in the Codell, Niobrara, D-Sand and J-Sand formations
with additional production from the deeper Dakota sandstones and the shallower
Sussex and Shannon sandstones. Drilling success rates have historically been
high, and production from these formations is characterized by strong initial
flows and long-lived reserves. Production also tends to be a combination of oil
and gas. Gas produced in the central part of the D-J Basin, including the
Wattenberg Field area ("Wattenberg"), has an energy content of approximately
1,250 Btu per Mcf, which enhances wellhead value.

One of the attractive features of D-J Basin geology is its multi-pay potential.
In a section only 3,500 feet thick, there are at least seven major potentially
productive formations. Three of the formations, the Codell, Niobrara and J-
Sand, are "blanket" zones in the area of the Company's Wattenberg holdings,
while others, such as the D-Sand and the shallower Shannon and Sussex, are more
localized.

Wattenberg Field Area. The majority of the Company's D-J Basin properties are
concentrated in Wattenberg, located approximately 35 miles north of Denver. With
the addition of the Amoco Properties, the Company's producing assets in this
area are comprised primarily of wells producing from the Codell, Niobrara and
J-Sand formations. The Codell and Niobrara formations are found at depths
ranging from 6,400 to 7,700 feet and the J-Sand is found between 7,400 and 7,800
feet. Codell and Niobrara wells produce oil and gas, while J-Sand wells produce
primarily gas. All of the gas from this field has high Btu content, allowing for
extraction of natural gas liquids.




                                       11
<PAGE>   12

Greater D-J Basin. The Greater D-J Basin is that portion of the D-J Basin
located generally south and east of Wattenberg. Production in the Greater D-J
Basin is generally found in D-Sand and J-Sand channels, and can produce oil, gas
or both. Within the D-Sand and J-Sand, high porosities and permeabilities can
yield higher flow rates than Wattenberg wells. D-Sand and J-Sand channels, while
not "blanket" formations, can be prolific when encountered. The D-Sand and
J-Sand are stratigraphically located below the Codell and Niobrara formations at
depths ranging from 6,800 to 7,800 feet.

Mid-Continent

The Company's Mid-Continent properties are primarily located in three geological
areas: (i) the Anadarko Basin in western Oklahoma and the Texas panhandle, (ii)
the Arkoma Basin in southeastern Oklahoma and western Arkansas and (iii)
southern Oklahoma.

Anadarko Basin. The Anadarko Basin is a major Mid-Continent oil and gas
producing area located in western Oklahoma and the Texas panhandle. The greatest
concentration of oil fields occurs on the eastern flank of the basin, with gas
fields dominating the shelf to the west, the Texas panhandle area and the deep
basin located in southwestern Oklahoma. The majority of the Company's production
comes from the Red Fork, Springer-Morrow, Chester, Mississippi and Hunton
formations. Oil and gas are produced in this basin from depths of only a few
hundred feet to over 20,000 feet, and most of the Company's wells produce from
depths between 6,000 and 16,000 feet.

Arkoma Basin. The Arkoma Basin is a crescent-shaped region straddling the
Arkansas-Oklahoma border. It is a major gas region, with most wells producing
from depths between 5,000 and 12,000 feet. The majority of the Company's
production comes from the Booch, Hartshorne, Atoka, Spiro and Cromwell
formations, primarily at depths between 5,000 and 10,000 feet.

South Oklahoma. The southern Oklahoma area is a faulted and folded geologic
province that extends across seven counties in south-central Oklahoma. The
Company's production is mainly from Pennsylvanian Hoxbar, Deese and Springer
sands, the Hunton and Viola carbonates, and the Simpson sand. The Company's
wells in this region produce from depths ranging from 5,000 to 17,000 feet.

Gulf Coast

The Company has established a core geographic area in onshore south Louisiana
and the upper Texas Gulf Coast. Its activities focus on both shallow
exploitation and deeper exploration targets in those areas. Focus areas are
Acadia, Jefferson Davis, Beauregard, Calcasieu, St. Landry and Evangaline
Parishes of south Louisiana and Chambers, Ft. Bend and Matagorda Counties in the
upper Texas Gulf Coast. Wells in the area target the Frio, Vicksburg, Cockfield,
Yegua, Sparta, and Hackberry formations at depths ranging from 3,000 to 13,500
feet. The complex faulted and prolific salt dome dominated region possesses
numerous reservoir targets that, in various combinations, provide attractive
multi-zone drilling prospects from as shallow as 6,500 feet to deeper than
12,000 feet.




                                       12
<PAGE>   13
Northern Rocky Mountains

HSR produces in two areas of the Northern Rocky Mountains, the Williston and
Green River Basins. The Company operates wells in two fields in the Daniels
County, Montana, portion of the Williston Basin. These wells produce from the
Ratcliffe, McGowan and Mission Canyon formations at depths ranging from 5,900 to
6,500 feet. The Company operates 18 wells in the Blue Forest Unit on the Moxa
Arch portion of the Green River Basin in Wyoming. The Blue Forest Unit currently
produces from the Frontier and Muddy formations found at depths of approximately
11,000 feet. Although most of HSR's gas production in Blue Forest Unit has been
sold under the TCW Facility, the Company has retained development, operating and
certain marketing rights.

PROJECT INVENTORY

The following table summarizes the Company's inventory of projects identified on
its properties as of December 31, 1997.

<TABLE>
         <S>                                                       <C>
         Development and exploitation locations . . . . . . . . .  2,200
         Potential infill locations . . . . . . . . . . . . . . .    700
         Recompletion and refrac locations  . . . . . . . . . . .  1,200
         Exploration leads and prospects  . . . . . . . . . . . .    315
         3-D seismic data (square miles)  . . . . . . . . . . . .    985
</TABLE>


Denver-Julesburg Basin Projects

The Company has a significant inventory of investment opportunities in the D-J
Basin. That inventory consists of development drilling on existing spacing,
behind-pipe recompletions, refrac projects, potential increased density
drilling, wellbore extensions, and exploration leads.

Wattenberg Field Area. The Company drilled 41 wells in Wattenberg during 1997,
accounting for additional production of approximately 2,541 Mcf of gas and 365
Bbl of oil production per day as of December 31, 1997. In addition to the over
2,100 opportunities provided by the Amoco Acquisition, HSR has in inventory 900
development drillsites, of which 584 are included in proved undeveloped
reserves. In addition, the Company has identified approximately 240 recompletion
opportunities in Wattenberg and at least 250 potentially economic infill
drillsites.

By combining the Amoco Properties with those previously owned by the Company,
HSR now owns numerous low-risk, potentially high-return development
opportunities. Because the Company owned formations that were vertically stacked
over and under formations previously owned by Amoco, the Company can now utilize
existing HSR or former Amoco wells to obtain potential reserves that were not
available or economic to either Amoco or HSR before the Amoco Acquisition. For
example, an existing HSR Codell well can be deepened a few hundred feet to reach
the J-Sand or Dakota formations previously owned by Amoco, or an existing Amoco
J-Sand well can be recompleted uphole to produce from the Codell, Niobrara,
Sussex or Shannon







                                       13
<PAGE>   14

formations that have been owned by HSR for some time but were not economically
attractive enough to justify the drilling of a new well. Production from the
various formations can generally be commingled.

The Company has also undertaken a program to increase Codell production from
existing wells through a process of restimulating (or "refracing") the currently
producing formation. The Company has completed 53 refracs through year end, all
of which were successful. Through the refrac process, the Company restimulated
each well to achieve production levels, reserve increases and decline profiles
approaching the well's initial characteristics. The Company believes that there
are more than 500 opportunities for this type of well stimulation. In addition,
gas production from many of the refrac candidates generate Section 29 tax
credits of approximately $0.60 per Mcf, which the Company monetizes under its
existing Section 29 monetization arrangements.

Greater D-J Basin. The Greater D-J Basin, in which the Company owns rights to
more than 173,000 gross undeveloped acres, provides HSR with significant
exploitation and exploration potential through the use of advanced technologies
such as 3-D seismic continuity processing and geostatistical analysis. In 1997,
the Company drilled and completed 21 wells, accounting for additional production
of approximately 1,146 Bbl of oil per day and 4,497 Mcf of gas per day. Thirteen
active projects and leads in this area are under review by the Company's
geotechnical staff.

Mid-Continent Projects

The Company has identified over 213 potential development and exploitation
drilling opportunities and 68 recompletion opportunities in the Mid-Continent.
In 1997, the Company participated in the drilling of 32 wells adding net
production of approximately 2,809 Mcf per day of gas as of December 31, 1997.
The Company also performed 20 recompletions.

In the Anadarko Basin, following the transfer of properties to Amoco in
connection with the Amoco Acquisition, the Company owns interests in 405 wells
in various fields which provide numerous potentially attractive development and
exploitation opportunities. The Company has identified approximately 84 drilling
and 51 recompletion opportunities in various fields. In 1997, the Company
drilled a successful well extending the existing Bivins Ranch field, creating
the opportunity for an additional three to five offset wells.

In the Arkoma Basin, the Company owns interests in 384 wells in the Kinta,
Bokoshe, Russellville, Wilburton and other fields. The Company has identified
approximately 129 drilling and 17 recompletion opportunities.

Other areas present additional opportunities. For example, with the use of 3-D
seismic data, the Company has identified further drilling opportunities at La
Reforma field in northwestern Hidalgo County, Texas, in which the Company owns
interests in a 5,100 acre contiguous block. The Company drilled two successful
wells at La Reforma in 1997 and expects to participate in an additional well in
1998. Further potential in this area is currently being evaluated.





                                       14
<PAGE>   15

Gulf Coast Projects

The Company's onshore Gulf Coast activity is focused in southwest Louisiana and
southeast Texas. The Company has been developing prospects in 18 active project
areas. To date, the Company has acquired over 530 square miles of 3-D seismic
data to support the exploration effort.

During 1997, the Company's Gulf Coast exploration program entered the drilling
phase on several projects. The Company participated in 16 gross wells, 11 of
which were successful. The most significant discovery is the HSR Carter #1 well
in the Roanoke project, which is currently producing 8.2 MMcf and 127 Bbl per
day. Gross year end reserves are estimated to be 2.5 million Boe for this well.

In addition, the Buhler project has now drilled nine successful wells in 11
attempts, with reserves averaging 512,000 Boe per well. Although the Company has
a small interest in the Buhler project, the technology gained from the program
has provided the basis for developing three additional project areas, in which
the Company's working interests range from 25% to 50%. For example, the North
Gillis program in Calcasieu Parish, Louisiana, in which the Company has a 37.5%
working interest, is a direct offset and analog to the successful Buhler
project. This project targets Hackberry and Yegua sands. The 3-D seismic survey
is complete with drilling to commence in the first half of 1998.

The Company has a 25% working interest in the Iowa/Welsh 3-D project operated by
Sonat Exploration, Inc. in Jefferson Davis Parish, Louisiana. The 135 square
mile 3-D seismic survey has been completed and initial drilling is expected to
follow in late 1998.

At the Port Barre project in St. Landry Parish, Louisiana, the Company has
completed the field acquisition phase of a 55 square mile 3-D seismic survey.
Initial drilling is expected to commence in the second half of 1998. The Company
has a 100% working interest in the Port Barre program.

Northern Rocky Mountain Projects

The Company's strategic focus for the Northern Rocky Mountain area is to
optimize production, fund exploratory activity through joint ventures, and
continue evaluation of undeveloped acreage. The Company has entered into
agreements with several operators with specific areas of technological or
operational expertise to evaluate and exploit certain of its large acreage
positions. By year end, this effort resulted in the drilling of four wildcats
with three additional wells currently being drilled, and the acquisition of over
73 square miles of 3-D seismic data.

For example, the Company has entered into an agreement with Union Pacific
Resources Company ("UPRC") on nearly 300,000 gross undeveloped acres in Daniels
County, Montana in the Williston Basin. Through the agreement, UPRC has drilled
two dual-lateral horizontal wells and one single-lateral horizontal well. All
three wells are currently on production and under evaluation.







                                       15
<PAGE>   16

In Richland and Roosevelt County, Montana, HSR has entered into joint venture
agreements with experienced local operators. These agreements resulted in the
drilling of two exploratory wells and the acquisition of 32 square miles of 3-D
seismic data. Both wells were dry holes. The seismic data is awaiting
interpretation.

The Company retains a significant acreage position in the Greater Green River
Basin, one of the most active areas in the Northern Rocky Mountains. New
geophysical, drilling and completion technologies appear to be unlocking
high-potential exploration opportunities targeting over-pressured basin-centered
gas.

ACREAGE

The Company's acreage positions have increased significantly, from approximately
9,000 developed and 37,000 undeveloped net acres as of December 31, 1991, to
approximately 671,271 developed and 780,821 undeveloped net acres as of December
31, 1997.

The following table sets forth the gross and net developed and undeveloped acres
on which the Company owns the rights to conduct exploration and development
activity as of December 31, 1997.


<TABLE>
<CAPTION>
                                Developed Acres (1)      Undeveloped Acres (1)
                               ---------------------     ---------------------
Area                            Gross         Net          Gross        Net
----                           -------     ---------     ---------    --------
<S>                            <C>         <C>           <C>          <C>
D-J Basin                      571,217       536,301       275,136     246,082
Mid-Continent                  349,279       130,030        33,862      28,572
Gulf Coast                       3,027           497       334,575     160,180
Northern Rocky Mountains        13,941         4,443       593,345     345,987
                               -------       -------     ---------     -------
Total                          937,464       671,271     1,236,918     780,821
                               =======       =======     =========     =======
</TABLE>


(1) Includes acres upon which the Company owns the rights to conduct seismic,
exploration and development activity but is not the lessee.


OIL AND GAS RESERVES

Two independent petroleum engineering consulting firms were engaged to review
the Company's estimates of its proved reserves, projected future production and
estimated future net revenues from production of proved reserves as of December
31, 1997. Williamson Petroleum Consultants, Inc. reviewed HSR's D-J Basin,
Northern Rockies and Gulf Coast properties, and Netherland, Sewell & Associates,
Inc. reviewed the Company's Mid-Continent reserves. Such estimates were based
upon a review of production histories and other geologic, economic, ownership
and engineering data provided by or available to the Company. In determining the
estimates of the reserve quantities that are economically recoverable, the
Company used selling prices and estimated development and production costs which
were in effect as of December 31, 1997. In accordance with guidelines
promulgated by the Securities and Exchange Commission, no price or cost
escalation or de-escalation was considered. The following table sets forth
information as of December 31, 1997, derived from the Company's reserve reports.
The present value (discounted at 10%) of estimated future net revenues before
income taxes shown in the table is not intended to represent the current market
value of the estimated oil and gas reserves




                                       16
<PAGE>   17


owned by the Company. In the aggregate, 84% of the Company's pre-tax present
value for the total proved reserves were reviewed by the two engineering firms.


<TABLE>
<CAPTION>
                                                        Net Proved Reserves
                                                      as of December 31, 1997
                                                  ---------------------------------
                                                  Developed   Undeveloped    Total
                                                  ---------   -----------  --------
<S>                                               <C>         <C>          <C>
Oil and condensate (MBbl)                          26,028       19,330       45,358
Gas (MMcf)                                        611,198      268,656      879,854
Equivalent barrels (MBoe)                         127,894       64,106      192,000
Present value of estimated
    future net revenues before income
    taxes (discounted at 10%) (in thousands)     $699,853     $122,613     $822,466
</TABLE>


There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting future rates of production and timing of development
expenditures, including many factors beyond the control of the Company. The
reserve data set forth herein represent only estimates. Reserve engineering is a
subjective process of estimating underground accumulations of oil and gas that
cannot be measured in an exact way, and the accuracy of any reserve estimate is
a function of the quality of available data and of engineering and geological
interpretation and judgment. As a result, estimates made by different engineers
often vary from one another. In addition, results of drilling, testing and
production subsequent to the date of an estimate may justify revision of such
estimates, either upward or downward, and such revisions may be material.
Accordingly, reserve estimates are often different from the quantities of oil
and gas that are ultimately recovered. Furthermore, the estimated future net
revenues from proved reserves and the present value thereof are based upon
certain assumptions, including prices, future production levels and cost, that
may not prove over time to have been correct.

Predictions about prices and future production levels are subject to great
uncertainty, and this is particularly true as to proved undeveloped reserves,
which are inherently less certain than proved developed reserves, and which
comprise a significant portion of the Company's proved reserves. Pricing
assumptions materially affect the calculation of present value of future net
revenues, principally in two ways. First, higher or lower prices directly affect
estimated cash flows attributable to a given reserve and production stream.
Second, higher or lower prices also increase or decrease the number of
potentially recoverable barrels of oil or cubic feet of gas. This is because
wells reach their economic limit earlier in a lower product price environment
than in a higher price environment, hence truncating the economic recovery of
reserves.

Oil and gas prices have fluctuated widely in recent years. The weighted average
sales prices utilized for the purposes of estimating the Company's proved
reserves and future net revenue therefrom at December 31, 1997, were $16.38 per
Bbl of oil and $2.31 per Mcf of gas. For cautions regarding forward-looking
statements made or implied by the Company see Item 7. "Management's Discussion
and Analysis of Financial Condition and Results of Operations--Disclosure
Regarding Forward-Looking Statements" and the Company's report on Form 8-K filed
with the Securities and Exchange Commission on February 26, 1997.

For further information concerning the present value of future net revenue from
the Company's proved reserves, see Note 14 of the Notes to Consolidated
Financial Statements.





                                       17
<PAGE>   18
Since December 31, 1990, as an operator of domestic oil and gas properties, the
Company has filed Department of Energy Form EIA-23, "Annual Survey of Oil and
Gas Reserves," as required by Public Law 93-275. There are differences between
the reserves as reported on Form EIA-23 and as reported herein. The difference
is attributable to the fact that Form EIA-23 requires that an operator report on
the total reserves attributable to wells which are operated by it, without
regard to ownership (i.e., reserves are reported on a gross operated basis,
rather that on a net interest basis), while reserves reported herein are net to
the Company.

DRILLING ACTIVITY

The following table sets forth the net wells drilled and completed by the
Company during the periods indicated.  Substantially all of the Company's wells
produce both oil and gas.


<TABLE>
<CAPTION>
                           Year Ended December 31,
                        ----------------------------
                         1997       1996       1995
                        ------     ------     ------
<S>                     <C>        <C>        <C>
Development:
     Productive           65.3      116.7       69.7
     Non-productive        5.3        0.0        5.4
                        ------     ------     ------
          Total           70.6      116.7       75.1
                        ------     ------     ------
Exploratory:
     Productive           14.2        3.5       21.3
     Non-productive        9.7        0.0       12.3
                        ------     ------     ------
          Total           23.9        3.5       33.6
                        ------     ------     ------
Total wells               94.5      120.2      108.7
                        ======     ======     ======
</TABLE>



PRODUCTIVE OIL AND GAS WELLS

The number of productive oil and gas wells, operated and non-operated, in which
the Company had an interest as of December 31, 1997, are as follows:


<TABLE>
<CAPTION>
                   Gross Productive Wells        Net Productive Wells
               ---------------------------  ------------------------------
                           Non-                           Non-
               Operated  Operated    Total  Operated    Operated    Total
               --------  --------    -----  --------    --------   -------
<S>            <C>       <C>         <C>    <C>         <C>        <C>
Oil              2,871     1,558     4,429   2,648.7       140.4   2,789.1
Gas                482       464       946     347.9        85.8     433.7
               -------   -------   -------   -------     -------   -------
     Total       3,353     2,022     5,375   2,996.6       226.2   3,222.8
               =======   =======   =======   =======     =======   =======
</TABLE>


Wells are classified as oil or gas producers as described in statutory
definitions based on oil/gas ratios.  As a result, most of the Company's wells
are categorized as oil wells, even though, on an equivalent Btu basis, such
wells tend to produce more gas than oil.



                                       18
<PAGE>   19
DEVELOPMENT, EXPLORATION AND ACQUISITION EXPENDITURES

The following table sets forth certain information regarding the costs incurred
by the Company in its development, exploration and acquisition activities
during the periods indicated (dollars in thousands).



<TABLE>
<CAPTION>
                                   Year Ended December 31,
                             -----------------------------------
                               1997          1996         1995
                             --------     --------     ---------
<S>                          <C>          <C>          <C>
Acquisition costs:
    Unproved properties      $131,262     $ 35,227     $  4,343
    Proved properties         167,825      338,814       25,015
Development costs              46,678       37,819       29,989
Exploration costs              12,856        2,100        2,748
                             --------     --------     --------
    Total costs incurred     $358,621     $413,960     $ 62,095
                             ========     ========     ========
</TABLE>


PRODUCTION

The following table sets forth the Company's oil and gas production data during
the periods indicated.


<TABLE>
<CAPTION>
                                            Year Ended December 31,
                                      --------------------------------
                                        1997        1996         1995
                                      -------     -------      -------
<S>                                   <C>         <C>          <C>
Net production:
    Oil and condensate (MBbl)           2,400       1,923       1,582
    Gas (MMcf)                         41,125      34,163      21,049
    Equivalent barrels (MBoe)           9,254       7,617       5,090
Average net daily production (1):
    Oil and condensate (Bbl)            6,679       5,255       4,333
    Gas (Mcf)                         117,589      93,342      57,670
    Equivalent barrels (Boe)           26,277      20,812      13,945
Average sales price per unit:
    Oil and condensate ($/Bbl)        $ 19.71     $ 20.90     $ 16.52
    Gas ($/Mcf)                       $  2.19     $  1.96     $  1.30
Lease operating expense ($/Boe)       $  2.69     $  2.32     $  1.95
</TABLE>


(1) Average daily production for 1997 was calculated for the quarter ended
    December 31, as the results are believed to be more indicative of current
    performance.





                                       19
<PAGE>   20

Item 3.          LEGAL PROCEEDINGS AND ENVIRONMENTAL ISSUES

Litigation. On July 22, 1997, Chenier Exploration, Inc. ("Chenier") brought suit
against the Company in the United States District Court for the Eastern District
of Texas (Chenier Exploration, Inc. v. HS Resources, Inc., Civil Action No.
1:97-CV-399) seeking damages and certain preliminary relief arising out of the
termination of an Exploration and Development Agreement ("Agreement") between
Chenier and the Company. The Agreement called for, among other things,
cooperation between the companies in the identification and development of oil
and gas prospects in the Gulf Coast regions of Louisiana and Texas. On August
22, 1997, the Court denied Chenier's requests for preliminary relief and granted
the Company's request that the remaining disputes between Chenier and the
Company be resolved in an arbitration conducted under the auspices of the
American Arbitration Association ("AAA") and entitled In re HS Resources, Inc.
and Chenier Exploration, Inc., AAA Arbitration No. 77-180-00171-97.

Chenier asserted that the Company breached express and implied provisions of the
Agreement in connection with its termination of that Agreement, that the Company
acted in bad faith in connection with the Agreement and that the Company
wrongfully interfered with employment and other existing and prospective
agreements involving Chenier in connection with the termination of the
Agreement. The Company denied each of these claims and believed it had
substantial legal defenses to each of the claims, and vigorously defended
against them. These claims were addressed in an arbitration hearing which
commenced on February 2, 1998, and ended February 17, 1998. On March 26, 1998,
the arbitrator issued a final award in favor of the Company denying each of
Chenier's claims for damages.

Additionally, the Company is subject to minor lawsuits incidental to operations
in the oil and gas industry. The Company believes it has meritorious defenses to
all lawsuits in which it is a defendant and will vigorously defend against them.
The resolution of such lawsuits, regardless of the outcome, will not have a
material adverse effect on the Company's results of operations or financial
position.

Environmental Proceedings. The owner of an oil field waste disposal facility, a
major oil company and the Company were named as respondents by the United States
Environmental Protection Agency ("EPA") in an administrative order brought by
the EPA against Weld County Waste Disposal, Inc. ("WCWDI") under section 7003 of
the Resource Conservation and Recovery Act ("RCRA") on May 11, 1995. WCWDI
operated and continues to own an evaporation pit in Colorado for the disposal of
non-hazardous production wastes. The EPA order requires that work be performed
to abate a perceived endangerment to wildlife, the environment or public
welfare. The Company and other non-operator respondents are working together
with the EPA to develop plans and characterization studies, and have caused the
facility to be permanently closed.

The Company has utilized this facility in past years to dispose of its
production and flowback water. During the period of its use, the Company
believed that the facility was operating in compliance with all applicable legal
requirements and, along with other oil and gas operators, paid a fee to WCWDI
for using this disposal facility. There were a number of other significant
contributors to the facility during the period reviewed by the EPA (1988 through
1994) and additional contributors during the period from 1977, when it was
constructed, through 1988. The Company and the major oil company were named
because they were deemed the major





                                       20
<PAGE>   21

contributors of waste volumes to the facility for the period reviewed by the
EPA. Certain other contributors are participating in their share of the
reclamation costs.

Based on the Company's current knowledge and its expectation of proportionate
reimbursement from other parties who utilized the facility, the Company does not
believe that its share of the reclamation costs will have a material impact on
its financial condition or results of operations. By agreement with other
contributing parties, the Company is currently paying approximately 50% of the
costs associated with the project, but after recovery from additional liable
parties, the Company's percentage share of overall costs may be reduced to as
low as 40%. The Company has spent approximately $1.4 million on its behalf to
date on the project. The Company's share of total costs associated with the
project, at the 50% level of participation, are currently estimated to range
from $1 to $2 million over three years. The full amount of the Company's
estimated liability is reflected in the December 31, 1997, financial statements.

Recent data regarding site conditions indicate a potentially more significant
contamination problem in one portion of the site which is the apparent result of
disposal of non-oil field wastes by third parties a number of years prior to the
Company's involvement as an oil field waste disposal customer of this facility.
This recent data gives rise to both the possibility of a defense of
non-liability for the divisible harm caused by wastes of third parties and
greater uncertainty regarding the total costs of study and clean-up for which
the Company is potentially liable. For these reasons, and because even the
selection of a remedial plan has yet to occur, the Company is not able at this
time to determine its probable share, if any, of future response costs for these
non-oil field wastes.


Item 4.          SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.





                                       21
<PAGE>   22
                                    PART II


Item 5.  MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

The Company's common stock (NYSE symbol "HSE") is traded publicly on the NYSE.
The following table presents the high and low sales prices reported by the NYSE
for the periods indicated. These prices do not include retail markups, markdowns
or commissions.

<TABLE>
<CAPTION>
 Quarter ended                        High          Low
--------------------                 ------      ---------
<S>                                  <C>         <C>
March 31, 1996                       13 1/8        9 1/4
June 30, 1996                        13 1/4        10 3/8
September 30, 1996                   14 1/8        11 3/4
December 31, 1996                    17 5/8        12 7/8
March 31, 1997                       18 3/8        11 1/2
June 30, 1997                        15            10 7/8
September 30, 1997                   17 7/8        13 3/16
December 31, 1997                    18 3/4        12 5/8
</TABLE>


As of December 31, 1997, there were 422 holders of record of the common stock.

The Company has never paid any cash dividends on its common stock, and the Board
of Directors of the Company does not currently intend to declare cash dividends
on its common stock. The Company instead intends to retain its earnings to
support the growth of the Company's business. Any future cash dividends would
depend on future earnings, capital requirements and the Company's financial
condition and other factors deemed relevant by the Board of Directors. The
Company's credit facility currently prohibits payment of dividends and the
indentures governing its outstanding 9 1/4% and 9 7/8% senior subordinated notes
due in 2006 and 2003, respectively, also limit the Company's ability to pay
dividends.



                                       22
<PAGE>   23

Item 6.  SELECTED FINANCIAL DATA

The following table sets forth selected financial data, as of the dates and for
the periods indicated, and is qualified in its entirety by reference to the
consolidated financial statements of HS Resources, Inc. included herein. See
also, Item 7. "Management's Discussion and Analysis of Financial Condition and
Results of Operations."







<TABLE>
<CAPTION>
                                                                         (In thousands, except per share amounts and average prices)
                                                                                                    For the Years Ended December 31,


                                                         1997             1996             1995             1994              1993
                                                 ------------      -----------      -----------      -----------      ------------
<S>                                              <C>               <C>              <C>              <C>              <C>
Statement of Operations Data
     Oil and gas sales                            $   137,251      $   107,281      $    53,394      $    58,827      $    45,382
     Trading and transportation                        90,062           46,373               --               --               --
     Other revenues                                     6,392            3,302            1,946            1,574            2,095
                                                  -----------      -----------      -----------      -----------      -----------
         Total revenues                               233,705          156,956           55,340           60,401           47,477
                                                  -----------      -----------      -----------      -----------      -----------

     Production taxes                                   9,703            8,195            4,050            5,134            4,222
     Lease operating expenses                          24,848           17,692            9,936            8,310            5,470
     Cost of trading and transportation                88,402           45,699               --               --               --
     Depreciation, depletion and amortization          53,241           42,335           26,609           25,079           15,299
     General and administrative expenses                7,987            5,642            4,076            4,228            3,123
     Interest expense                                  31,204           22,936           10,219            7,539            3,118
                                                  -----------      -----------      -----------      -----------      -----------
         Total expenses                               215,385          142,499           54,890           50,290           31,232
                                                  -----------      -----------      -----------      -----------      -----------
     Income before provision for income
         taxes                                         18,320           14,457              450           10,111           16,245
     Provision for income taxes                        (6,980)          (5,508)            (176)          (3,852)          (6,189)
                                                  -----------      -----------      -----------      -----------      -----------
     Net income                                   $    11,340      $     8,949      $       274      $     6,259      $    10,056
                                                  -----------      -----------      -----------      -----------      -----------
     Diluted earnings per share                   $      0.64      $      0.61      $      0.02      $      0.53      $      0.93
                                                  -----------      -----------      -----------      -----------      -----------
     Weighted average number of common shares
         outstanding assuming dilution                 17,593           14,552           11,439           11,713           10,858
                                                  -----------      -----------      -----------      -----------      -----------
Balance Sheet Data
     Working capital (deficiency)                 $    (9,042)     $    13,749      $   (16,115)     $    (2,384)     $    16,221
     Oil and gas properties, net                      959,536          652,180          278,811          242,009          184,188
     Total assets                                   1,034,603          731,285          302,089          269,070          228,260
     Long-term debt, net of current portion           636,699          398,563          125,537          103,478           74,420
     Deferred income taxes                             90,798           84,829           23,604           23,432           19,589
     Stockholders' equity                             223,622          192,724          119,174          119,358          113,299
Operating Data
     Average sales price per barrel of oil        $     19.71      $     20.90      $     16.52      $     14.83      $     16.09
     Average sales price per thousand
         cubic feet of gas                        $      2.19      $      1.96      $      1.30      $      1.70      $      2.03
Production
     Oil (MBbl)                                         2,400            1,923            1,582            1,664              967
     Gas (MMcf)                                        41,125           34,163           21,049           20,108           14,684
     MBoe                                               9,254            7,617            5,090            5,015            3,414

Net cash provided by
     operating activities                         $    94,019      $    52,251      $    31,179      $    36,553      $    33,745
</TABLE>



                                       23
<PAGE>   24
Item 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
         RESULTS OF OPERATIONS

GENERAL For the last several years the Company pursued a strategy that included
(i) building a substantial inventory of development, exploitation and
exploration projects, (ii) consolidating in its core geographic areas,
particularly the Denver-Julesburg ("D-J") Basin, (iii) diversifying its asset
base into multiple geographic and geologic regions of the United States, (iv)
capturing more of the value stream by marketing its production and (v)
maximizing its financial flexibility. The Company's success over the past 18
months in accomplishing these goals has positioned the Company for a period of
significant growth in reserves, production, and cash flow. Having achieved its
historic goals, the Company has now adopted the four part strategy involving
Consolidation, Exploitation, Exploration and Technology discussed in Item 1.
"BUSINESS STRATEGY."

Through the 1997 acquisition of all of Amoco Production Company's D-J Basin
properties (the "Amoco Acquisition") and the 1996 acquisition of all of the D-J
Basin properties owned by Basin Exploration, Inc. (the "Basin Acquisition"), the
Company has expanded its D-J Basin asset base and significantly increased its
inventory of development, exploitation and exploration opportunities. As a
result of the 1996 merger (the "Merger") with Tide West Oil Company ("Tide
West"), and by establishing an active Gulf Coast exploration program, the
Company also has developed a substantial base of assets outside of the D-J
Basin.

Through the execution of its strategy, the Company now operates in four core
areas. Additionally, the Company's strategically important and profitable
presence in the gas marketing, trading and transportation business through its
subsidiary, HS Energy Services, Inc. ("HSES"), provides opportunities for the
Company to enhance its operating margins on production from each of its
producing areas.

The Amoco Acquisition presents the Company with new opportunities, challenges
and potential directions. That acquisition, in combination with the Company's
recent success in finding new D-J Basin reserve potential through scientific,
technical and operational advances, materially increases the number of low-risk,
high-return projects that the Company owns in the D-J Basin. Therefore, based on
its existing inventory of opportunities, the Company expects that the D-J Basin
will once again become dominant in the Company's strategy for growth. However,
as the Company pursues its D-J Basin growth opportunities it will also continue
to pursue development in its other core areas.

The Amoco Acquisition required the Company to borrow funds, which has increased
its leverage ratios significantly. As a result, although the Company has
executed a number of commodity price and interest rate hedge agreements designed
to moderate this risk, the current level of debt will increase interest expense
and make the Company more vulnerable to changes in interest rates and commodity
prices. The increased activities in the D-J Basin, however, are expected to
reduce the Company's per unit production costs, as discussed below. For various
reasons, as discussed in Item 7. "LIQUIDITY AND CAPITAL RESOURCES--Financing
Sources" below, the Company believes the current level of debt is acceptable,
although it is considering a wide range of future financing alternatives.

OIL AND GAS PRICES The United States oil and gas industry is subject to large
variations in profitability due in part to fluctuating commodity prices and
related changes in rates of reinvestment by industry participants. Through 1997,
several factors had a positive effect on





                                       24
<PAGE>   25
production economics in the Company's core geographic areas as compared to the
period 1994 through 1995. These include (i) relatively high wellhead capacity
utilization, (ii) increasing overall gas demand, (iii) deregulation of
distribution and marketing channels, particularly for D-J Basin and Rocky
Mountain production, and expansion of pipeline capacity to transport gas to
markets outside the Colorado Front Range and (iv) successful application of
advanced oil and gas exploration, drilling and production technologies. However,
uncertainty concerning the price of oil and gas remains a dominant and
unpredictable factor in the Company's profitability.

GAS PRICE CONSIDERATIONS Approximately 81% of the Company's proved producing
reserves consist of gas located in the D-J Basin and Mid-Continent areas. The
absolute level and volatility of gas prices have a material impact on the
Company.

Since the beginning of 1996, the market for the Company's D-J Basin gas has
strengthened substantially due to several factors. First, excess supply from
Wyoming gas producers has declined as a result of increased demand from West
Coast markets. Second, in October 1995 the Colorado Public Utilities Commission
("CPUC") approved tariff changes that effectively eliminated transportation
costs for D-J Basin gas sold to the Colorado Front Range market, resulting in a
transportation cost advantage for D-J Basin producers of approximately $0.40 per
million British thermal units ("MMBtu"). Some of this advantage may be
eliminated if the application filed by Public Service Company of Colorado
("PSCO"), discussed below, is approved in its current form. Third, the supply of
D-J Basin gas has declined over the last two years due to the combination of
reduced drilling in the D-J Basin and natural production declines. The average
price received by the Company for its D-J Basin gas production has increased
from $1.28 per Mcf in 1995 to $1.90 per Mcf in 1996 and to $2.13 per Mcf in
1997. In addition, expansion of pipeline capacity has provided additional
transportation outlets for Wyoming producers to markets other than the Colorado
Front Range and also provided Colorado Front Range producers with access to
other markets.

As a result of these developments, the disparity between D-J Basin pricing and
pricing generally available elsewhere in the United States has been reduced.
Historically, the price of D-J Basin gas (on a Btu-equivalent basis) has been
linked closely to the Colorado Interstate Gas Company ("CIG") pipeline Rocky
Mountain Index. More recently, however, as a result of the developments
discussed above and the seasonal nature of demand in the Colorado Front Range,
during the low demand summer months (generally April through October) the price
for D-J Basin gas tends to reflect the CIG Rocky Mountain Index, whereas during
the high demand winter periods (generally November through March) the price more
closely tracks Mid-Continent indices.

In recent months two proposals have been filed to build pipelines between the
Colorado Front Range market area and Wyoming. A subsidiary of K N Energy has
proposed a 250 MMcfd capacity pipeline which is currently before the Federal
Energy Regulatory Commission. PSCO and CIG, through a jointly owned affiliate,
have proposed a 270 MMcfd capacity line. As proposed, the PSCO line would be
operated as part of PSCO's local distribution system, moving the city gate to
PSCO's Chalk Bluffs measurement station near the Wyoming border. If approved as
proposed, this would eliminate some portion of the advantage the Company
currently has over





                                       25
<PAGE>   26
Wyoming producers for direct sales in the Colorado Front Range market. The PSCO
application is currently before the CPUC. Approval of either or both of these
pipelines would increase the amount of Wyoming gas that could be transported to
the Colorado Front Range market, while also expanding the amount of gas that
could be exported from the D-J Basin to Mid-Continent and West Coast markets
through Wyoming pipeline interconnections. The Company has intervened in both
the K N Energy and PSCO application proceedings, and is protesting the PSCO
application. The Company cannot predict whether these pipeline applications will
be approved, amended or denied, nor what would be the ultimate effect on the
price of the Company's D-J Basin gas if either or both are approved.

Gas prices in the Mid-Continent are closely tied to established indices which
are influenced by national supply and demand factors. Average gas prices
received by the Company in the Mid-Continent generally fluctuate with changes in
Mid-Continent posted prices, which for the years 1993 through 1997 averaged
$0.24 per MMbtu less than the Henry Hub price. The average gas price received in
the Mid-Continent since the Merger in June 1996 through December 31, 1997, was
$2.29 per Mcf, or $0.27 below the Henry Hub price, before considering the
effects of hedging.

OIL PRICE CONSIDERATIONS Oil prices are established in a highly liquid
international market. Average oil prices received by the Company in the D-J
Basin and Mid-Continent generally fluctuate with changes in the NYMEX West Texas
Intermediate crude oil closing prices. Weaknesses in the world oil demand
coupled with increasing supplies from the Middle East led to weak oil prices
over the recent winter months, reaching a four-year low before recovering
somewhat in the most recent two weeks. The Company is unable to predict the
future trend in oil prices.

RESULTS OF OPERATIONS During 1997 the Company continued drilling and development
activity in the D-J Basin, exploitation and exploration activities in the
Mid-Continent and the Gulf Coast regions and completed the Amoco Acquisition. At
December 31, 1997, the Company owned interests in more than 5,300 producing
wells (of which it operated more than 3,300) compared to 3,500 wells (of which
it operated more than 2,600) at December 31, 1996. The Company's results of
operations have been significantly affected by the Basin Acquisition and the
Merger, by its drilling program and by fluctuations in oil and gas prices.
Future results will also be significantly affected by the Amoco Acquisition and
the Company's exploration, exploitation and development activities.

Per unit lease operating expense ("LOE") and general and administrative ("G&A")
costs are expected to decrease due to efficiencies in combining the assets
acquired in the Amoco Acquisition with the Company's previously existing asset
base. These benefits will be offset to some extent by the increase in interest
expense attributable to the Company's expected debt level. In the Amoco
Acquisition, the Company purchased 2,068 producing wells in the D-J Basin as
well as more than 2,100 low-risk development opportunities. At December 31,
1997, production attributable to the producing wells acquired from Amoco totaled
8,353 Boe per day, increasing the Company's overall production, revenues and
cash flow. In addition, the Company plans to increase its development activities
in the D-J Basin to exploit the large number of development opportunities in
this area.





                                       26
<PAGE>   27
The United States oil and gas industry is currently experiencing regional
shortages of drilling and completion equipment and skilled workers. This
shortage has resulted in higher costs for the Company's drilling and related
field activities, primarily in its Gulf Coast and Mid-Continent district
operations. The Company anticipates this shortage will continue for the
foreseeable future.

COMPARISON OF YEARS ENDED DECEMBER 31, 1997 AND 1996

OIL AND GAS REVENUES For the comparative periods, oil production increased from
1,923 MBbl to 2,400 MBbl and gas production increased from 34,163 MMcf to 41,125
MMcf, or 25% and 20%, respectively. Average realized oil prices decreased by 6%
from $20.90 to $19.71 per Bbl and average realized gas prices increased by 12%
from $1.96 to $2.19 per Mcf. The production increases were primarily the result
of additional production from the properties acquired in the Basin Acquisition
and the Merger and new wells drilled by the Company. The net effect of these
changes resulted in an increase in oil and gas revenues from $107 million to
$137 million, or 28%. In 1997 the Company also recognized $4.4 million in other
gas revenues from the sale of tax credits compared to $2.7 million in 1996, as
discussed in Note 11 of the Notes to Consolidated Financial Statements.

Through its wholly owned subsidiary HSES, the Company markets its own gas
production as well as that of third parties. A portion of this gas is sold
directly to end users, while other amounts are used as the equity-gas foundation
for a physical trading business in which gas volumes may be traded several times
at different receipt and delivery points in order to capture the greatest margin
possible. Trading and transportation net margins were $1.7 million at December
31, 1997, compared to $0.7 million at December 31, 1996.

INTEREST INCOME AND OTHER INCOME Interest and other income increased by $1.4
million, or 234%, for the year ended December 31, 1997. The increase was mainly
due to interest received for prior year severance tax refunds, short term
investing of the Company's available funds, and income recorded on the Company's
interest in a limited partnership.

PRODUCTION EXPENSES LOE increased by $7.2 million, or 40%, due to an increase in
the number of producing wells. On a per Boe basis, LOE increased from $2.32 to
$2.69 for the comparative periods, which is primarily the result of a different
mix of wells in the current year, including wells with historically higher
operating costs which were obtained as a result of the Basin Acquisition, and a
significant number of workovers on producing wells. LOE per Boe is expected to
decrease in 1998 as the efficiencies of consolidation of the Amoco assets are
realized. Production taxes increased by $1.5 million, or 18%, due to increased
production and prices. Production taxes in 1997 reflect an adjustment for prior
year severance tax refunds.

DEPRECIATION, DEPLETION AND AMORTIZATION DD&A, a non-cash expense, increased
$10.9 million, or 26%, due to an increase in production and an increase in the
depletion rate. For the year ended December 31, 1997, the Company had a weighted
average depletion rate of $5.54 per Boe ($5.89 for the quarter ended December
31, 1997) compared to $5.33 per Boe for the year ended December 31, 1996. The
Company annually adjusts its DD&A rate based on year end engineering and, if
material changes in its reserves warrant, on an interim basis.







                                       27
<PAGE>   28

GENERAL AND ADMINISTRATIVE EXPENSE G&A expense reflects costs incurred, net of
administrative costs directly attributable to drilling and well operations
(which costs are included in LOE or are capitalized). G&A expenses increased
$2.3 million, or 42%. The increase for the comparative periods is primarily
attributable to the administrative costs resulting from the Merger and the
greater number of Tide West employees, as well as the addition of personnel and
facilities throughout 1997 which were required in order to accomplish the
Company's acquisition, drilling and exploration objectives. On a per Boe basis,
G&A expenses increased from $0.74 to $0.86 for the comparative periods. The
current year per Boe amount is generally in line with prior years, but is
expected to decrease as the D-J Basin assets are developed and produced in 1998.
The period-over-period comparative difference results substantially from the
abnormally low costs incurred by the Company in the prior year, particularly
during the transitionary period immediately after closing the Basin Acquisition
and the Merger. During that transitionary period costs were anomalously low
while the Company hired additional staff to handle the ongoing requirements
attributable to the increase in operations.

INTEREST EXPENSE Interest expense increased $8.3 million, or 36%, due to the
overall increase in long-term debt attributable to the Basin Acquisition and the
Merger as well as amounts borrowed in December 1997 to fund the Amoco
Acquisition. Interest expense is expected to increase significantly in 1998 due
to increased borrowings used to fund the Amoco Acquisition.

PROVISION FOR INCOME TAXES The Company follows the provisions of Statement of
Financial Accounting Standards ("SFAS") No. 109. Pursuant to SFAS 109, the
Company has recorded a tax provision based on tax rates in effect during the
period. Accordingly, the Company accrued taxes at the rate of 38.1% in 1997 and
1996. Due to significant intangible drilling costs, which are deductible for
income tax purposes, substantially all of the Company's tax provision in both
periods is deferred.

COMPARISON OF YEARS ENDED DECEMBER 31, 1996 AND 1995

OIL AND GAS REVENUES For the comparative periods, oil production increased from
1,582 MBbl to 1,923 MBbl and gas production increased from 21,049 MMcf to 34,163
MMcf, or 22% and 62%, respectively. Average realized oil prices increased by 27%
from $16.52 to $20.90 per Bbl and average realized gas prices increased by 51%
from $1.30 to $1.96 per Mcf. The production increases were the result of
additional production from the properties acquired in the Basin Acquisition and
the Merger and new wells drilled by the Company. The net effect of these changes
resulted in an increase in oil and gas revenues from $53.4 million to $107.3
million or 101%. The Company also recognized $2.7 million in other gas revenues
from the sale of tax credits with respect to its Section 29 tax credit
agreements for the year ended December 31, 1996, as discussed in Note 11 of the
Notes to Consolidated Financial Statements.







                                       28
<PAGE>   29

As discussed above, the Company, through its wholly owned subsidiary HSES,
markets its own gas production as well as that of third parties. Trading and
transportation net margins were $0.7 million at December 31, 1996. There were no
comparable revenues in 1995.

INTEREST INCOME AND OTHER INCOME Interest and other income increased by
$418,557, or 256%, for the year ended December 31, 1996. The increase in
interest and other income was mainly due to short term investing of the
Company's available funds, as well as a gain recorded on the sale of assets of
$118,649.

PRODUCTION EXPENSES LOE increased by $7.8 million, or 78%, due to an increase in
the number of producing wells. LOE per Boe increased from $1.95 to $2.32 for the
comparative periods. This increase is primarily the result of a different mix of
wells, including wells with historically higher operating costs which were
acquired as a result of the Basin Acquisition. Production taxes increased by
$4.1 million, or 102%, due to increased production and prices. Production taxes
in 1996 reflect an adjustment for a reduction in the Company's severance tax
rate. A cumulative rate adjustment for 1995 was recorded in the third quarter of
1995.

DEPRECIATION, DEPLETION AND AMORTIZATION DD&A, a non-cash expense, increased
$15.7 million, or 59%, due to an increase in production and an increase in the
depletion rate. For the year ended December 31, 1996, the Company had a weighted
average depletion rate of $5.33 per Boe ($5.41 for the quarter ended December
31, 1996). The Company annually adjusts its DD&A rate based on year end
engineering, and, if material changes in its reserves warrant, on an interim
basis.

GENERAL AND ADMINISTRATIVE EXPENSE G&A expense reflects costs incurred, net of
administrative costs directly attributable to drilling and well operations
(which costs are included in LOE or are capitalized). G&A expenses increased
$1.6 million, or 38%. The increase for the comparative periods is primarily
attributable to the Merger and retention of the former Tide West employees. On a
per Boe basis, G&A expenses decreased from $0.80 to $0.74 for the comparative
periods.

INTEREST EXPENSE Interest expense increased $12.7 million, or 124%, due to
increased borrowings on the Company's long-term bank debt. Also, in November
1996, the Company issued $150 million of its 9 1/4% senior subordinated notes
due in 2006.

PROVISION FOR INCOME TAXES The Company follows the provisions of SFAS No. 109.
Pursuant to SFAS 109, the Company has recorded a tax provision based on tax
rates in effect during the period. Accordingly, the Company accrued taxes at the
rate of 38.1% in 1996 and 1995. Due to significant intangible drilling costs,
which are deductible for income tax purposes, substantially all of the Company's
tax provision in both periods is deferred.







                                       29
<PAGE>   30

LIQUIDITY AND CAPITAL RESOURCES

Financing Sources

At December 31, 1997, the Company's overall debt level was significantly higher
than in previous periods as a result of borrowings used to fund the Amoco
Acquisition. The Company believes that its current level of debt and leverage is
acceptable at present, although the Company may elect to reduce or refinance
such debt levels at any time. The Company's debt is supported by stable,
long-lived reserves and by the Company's hedging programs, with product prices
hedged for reasonable periods of time at favorable prices. Cash flow from
producing activities is sufficient to enable the Company to service its debt,
absent any major and prolonged period of price declines. The Company has a large
number of low-risk, potentially high-return exploitation projects which should
enhance production and cash flow per share. In light of this view, and as part
of an overall financing strategy, the Company is considering a wide range of
future financing alternatives and is not committed to any particular course.

In undertaking any future financing transactions, the Company will seek to
achieve the optimal capital structure needed to support its long-term strategic
objectives. Any such financings will reflect market conditions at the time and
may include the issuance of long-term debt, equity, or equity-linked securities.
In addition to or perhaps in lieu of the issuance of such securities, to
optimize its capital structure the Company may sell or monetize certain
properties, which would also minimize the equity dilution which would otherwise
result from the issuance of additional equity securities. Depending on the
nature and size of such property sales, the Company's production could become
more concentrated in one or more of its existing producing regions.

Because of its increased leverage, the Company currently plans to fund capital
expenditures attributable to exploration, exploitation and development
activities primarily out of its expected cash flow from operations. Accordingly,
the level and volatility of oil and gas prices may be expected to affect the
Company's capital expenditure activities.

On December 15, 1997, as a result of the Amoco Acquisition, the Company's
revolving senior bank credit facility with The Chase Manhattan Bank, as Agent
(the "Chase Facility"), was amended to increase the maximum credit amount and
the borrowing base to $450 million and to revise the interest rate payable
thereunder to the Base Rate plus 0% to 0.625% or LIBOR plus 0.75% to 1.625%.
Under the terms of the Chase Facility, no principal payments are required until
December 15, 2002, assuming the Company maintains a borrowing base sufficient to
support the outstanding loan balance. As of December 31, 1997, $412 million was
outstanding under the Chase Facility. The facility consists of a borrowing base
(currently $450 million) and a threshold amount (currently $400 million --
representing what a fully conforming loan borrowing base would be). The
borrowing base is based on the underlying value of the Company's oil and gas
properties. The borrowing base will remain $450 million until September 15,
1998, at which point it may be redetermined. Until that time, if the Company
issues equity or debt securities, or sells or otherwise disposes of properties,
net proceeds of such transactions must be applied to the repayment of debt under
the facility. The outstanding amounts under the facility must be reduced to or
below the threshold amount by September 15, 1998.







                                       30
<PAGE>   31

In November 1996, in a private offering exempt from securities registration, the
Company issued $150 million of its 9 1/4% senior subordinated notes due in 2006
(the "Notes"). The offering of the Notes was undertaken in order to replace with
fixed rate term debt a portion of the Company's outstanding indebtedness under
the Chase Facility. On April 25, 1997, the Company exchanged $150 million of new
notes registered under the Securities Act of 1933 (the "New Notes") for the
Notes. The material terms of the New Notes are identical to those of the Notes.

The Company also maintains its arrangement with a Trust Company of the
West-related entity covering a $90 million non-recourse, volumetric overriding
royalty facility (the "TCW Facility") of which approximately $80 million is
available. Proceeds from the TCW Facility may be used by the Company at its
discretion for a variety of corporate purposes, including acquisitions of new
properties, exploration and development drilling and monetization of existing
corporate properties.

The Company anticipates that its available borrowing capacity under the Chase
Facility, combined with its operating cash flow and the TCW Facility, will
provide it with financial resources and flexibility to fund current and ongoing
development activities and to meet other financial obligations. The nature of
the Company's current development strategies and other activities provide the
Company with considerable flexibility in terms of the timing and magnitude of
its capital expenditures. If the Company experiences unforeseen changes in its
working capital position or capital resources, management may revise the capital
expenditure program accordingly or alternatively may supplement the capital
position of the Company through, among other things, the issuance of additional
equity, equity-linked or debt securities, the sale or monetization of properties
or by entering into joint venture arrangements.

Capital Commitments

The Company continuously evaluates its inventory of drilling opportunities to
develop a growth-oriented portfolio of risk-balanced development, exploitation
and exploration opportunities. On an ongoing basis, the Company adjusts the
amount and allocation of its capital program based on a number of factors,
including seismic results, prospect readiness, product prices, service company
availability and rates, acquisitions and capital position. For the twelve months
ended December 31, 1997, the Company incurred total exploration, development and
leasehold capital expenditures of $75.1 million. The Company estimates that
capital expenditures for 1998 will be approximately $90-$100 million, which will
be allocated in varying amounts primarily to activities in the Company's four
core geographic areas: the D-J Basin, the Northern Rocky Mountains, the Anadarko
and Arkoma Basins of the Mid-Continent and the onshore Gulf Coast region.

A major component of the Company's capital expenditure program relates to its
development activities in the D-J Basin. The Company incurred approximately
$29.2 million in capital expenditures in 1997 for drilling, recompleting and
refracing the Company's D-J Basin properties, and anticipates allocating $60-$75
million in the D-J Basin in 1998.







                                       31
<PAGE>   32
 A second component of the Company's capital expenditure program is the
continued exploitation of the properties acquired as a result of the Merger with
Tide West. The Company incurred total exploitation and development expenditures
in the Mid-Continent area of $10.8 million during 1997. The Company is currently
evaluating a variety of opportunities in the Mid-Continent that include
increased exploitation, exploration and density drilling, recompletions and
field extensions. The Company anticipates allocating $10-$15 million to these
Mid-Continent projects in 1998.

Another component of the Company's capital expenditure program is to develop
exploitation and exploration prospects in the onshore portion of the Gulf Coast.
In 1997 the Company incurred total capital expenditures of $26.6 million in the
Gulf Coast. This includes approximately $15.3 million of expenditures under its
SouthTech joint venture and $11.3 million on its other Gulf Coast projects, for
seismic, leasehold, overhead costs and drilling. The Company anticipates
allocating $15-$20 million to Gulf Coast projects in 1998.

Activities during 1997 in the Company's Northern Rockies area were designed to
utilize the Company's extensive acreage position as a vehicle for generating
capital expenditures by third party operators on HSR's acreage. During 1997
approximately $10 million was spent or committed to by others to test plays and
concepts on HSR's acreage, with HSR retaining significant positions for
exploiting successful discoveries.

The Company has also entered into a number of other standard industry
arrangements that require the drilling of wells or other activities. The Company
believes that it will meet its obligations under these arrangements, which
individually and in the aggregate are not material.

Working Capital and Cash Flow

Net cash provided by operating activities for the year ended December 31, 1997,
was $94 million, up from $52.3 million for the same period in 1996. This
increase is primarily the result of (i) additional oil and gas production
revenues attributable to the larger number of producing wells resulting from the
Company's drilling activities and the wells acquired in the Basin Acquisition
and the Merger, and (ii) higher gas prices, which were partially offset by lower
oil prices. Future cash flows will be influenced by, among other factors, the
number of producing wells on line, product prices and production constraints.

Risk Management

The Company uses financial instruments to reduce its exposure to market
fluctuations in the price and transportation cost of oil and gas. The Company's
general strategy is to hedge price and location risk with swap, collar, floor
and ceiling arrangements. In order to minimize risk, to the maximum extent
possible, the Company hedges its production back to the wellhead. In addition to
hedging activities, the Company is engaged in using the financial markets to
capture trading margins. The Company has established policies with respect to
open positions which limit its exposure to market risk and requires daily
reporting to management of the potential financial exposure resulting from both
hedging and trading activities.







                                       32
<PAGE>   33

Hedging Activities

Activities for hedging purposes are entered into by the Company to manage its
exposure to price and location risks in the marketing of its oil and gas
production and, in the case of its marketing activities, third party gas. Gains
and losses on hedging positions are recognized in the period during which the
underlying physical transactions occur and are booked in "oil and gas sales"
(for company-owned production) and "trading and transportation revenues" (for
third party gas).

The Company's general strategy is to hedge price and location risk with swap,
collar, floor and ceiling arrangements. As a part of its risk management
program, the Company generally enters into hedges for delivery into one of the
two pipelines located near its producing regions, Panhandle Eastern Pipeline
Company ("PEPL") or CIG, or at the New York Mercantile Exchange ("NYMEX") prices
settled at the Henry Hub. With respect to the NYMEX-hedged volumes that exceed
the Company's Gulf Coast volumes, the Company usually hedges basis to its
producing regions at such time as the Company deems advantageous. Currently, the
Company holds hedge swap positions as follows:




<TABLE>
<CAPTION>
                            Average Daily
                               Volume         Settlement         Price
     Time Period              (MMBtu)          Location        (per MMBtu)
     -----------            --------------    ----------       -----------
<S>                         <C>               <C>              <C>
 January-March 1998            10,000            CIG              $2.21
                               50,000            PEPL             $2.53
                               25,000           NYMEX             $2.54
 April-October 1998            25,000            CIG              $1.66
                               20,000            PEPL             $2.03
                               16,000           NYMEX             $2.22
</TABLE>




The Company has hedged approximately 24% of its expected 1998 oil production at
$19.52 per Bbl. Additionally, with respect to the hedging of third party gas,
the Company has hedged 12.5 Bcf through December 1998 with offsetting physical
positions at settlement prices which are based upon NYMEX future prices or other
published indices.

Trading Activities

The Company engages in the trading of various energy related financial
instruments which require payments to (or receipt of payments from)
counterparties based on the differential between a fixed and a variable price
for the commodity, swap or other contractual arrangement. Activities for trading
purposes are accounted for using the mark-to-market method. Under this method,
changes in the market value of outstanding financial instruments are recognized
in







                                       33
<PAGE>   34

"trading and transportation revenues" as a net gain or loss in the period of
change. The market prices used to value these transactions reflect management's
best estimate considering various factors, including closing exchange and over-
the-counter quotations, time value and volatility factors underlying the
commitments. The values are adjusted to reflect the potential impact of
liquidating the Company's position in an orderly manner over a reasonable period
of time under present market conditions.

Company policy requires that, within defined trading limits, financial
instrument purchase and sales contracts be balanced in terms of contract volumes
and the timing of performance and delivery obligations. As of December 31, 1997,
all material open positions were balanced with an offsetting position. During
1997, gains of $453,821 were recognized in connection with these activities and
are included in "trading and transportation revenues."

Credit Risk

While notional amounts are used to express the volume of various derivative
financial instruments, the amounts potentially subject to credit risk in the
event of nonperformance by the third parties are substantially smaller.
Counterparties to the swap, collar, floor and ceiling arrangements discussed
above are investment grade financial institutions. Accordingly, the Company does
not anticipate any material impact to its financial position or results of
operations as a result of nonperformance by the third parties to financial
instruments related to hedging activities or trading activities.

Interest Rate Swaps

During the second quarter of 1995, the Company entered into an interest rate
exchange agreement with a financial institution to hedge its interest rate on
$40 million of the Company's borrowings at 7.76% through May 2002. Under the
terms of the agreement, the difference between the Company's fixed rate of 7.76%
and the three month LIBOR rate plus 1.125% is received or paid by the Company.

The Company, through the Merger, assumed interest rate exchange agreements with
two financial institutions to hedge its interest rates on a total of $40 million
of the Company's borrowings at rates ranging from 6.16% to 7.32% for 1997
through 1999. Under the terms of these agreements, the difference between the
Company's fixed rate and the three month LIBOR rate is received or paid by the
Company.

Contingencies

In May 1995, the Company was named as a respondent by the United States
Environmental Protection Agency (the "EPA") in an administrative order brought
under the Resource Conservation and Recovery Act ("RCRA") by the EPA against the
owner/operator of an oilfield production water evaporation facility. Based on
its evaluation of the above matters, and after consideration of reserves
established, the Company believes the resolution of such matters will not have a
material adverse effect on the Company's financial condition or results of
operations.







                                       34
<PAGE>   35

See Item 3. "Legal Proceedings and Environmental Issues" and Note 10 of the
Notes to Consolidated Financial Statements.

Year 2000

The Company has completed a review of its systems and infrastructure to
determine the extent of the work needed to ensure Year 2000 compliance. A plan
is being developed to test and verify Year 2000 compliance, including making the
necessary modifications, for all systems and processes. The Company will
continue to evaluate the estimated costs associated with these efforts based on
the results of this work. While these efforts involve additional costs, based on
available information, the Company believes that these costs will not be
material to its results of operations.







                                       35
<PAGE>   36

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

This 10-K Report includes statements that are not purely historical and are
"forward-looking statements" within the meaning of Section 27A of the Securities
Act and Section 21E of the Securities Exchange Act of 1934, as amended,
including statements regarding the Company's expectations, hopes, beliefs,
intentions or strategies regarding the future. All statements other than
statements of historical facts included in this 10-K Report, including without
limitation, statements under "Business," "Properties," "Legal Proceedings and
Environmental Issues," "Management's Discussion and Analysis of Financial
Condition and Results of Operations," and the "Notes to Consolidated Financial
Statements" regarding reserves and their values, planned capital expenditures,
increases in oil and gas production, trends or expectations concerning oil and
gas prices, the number and prospective nature of anticipated wells to be drilled
in 1998 and thereafter, development, infill and drillsite potential,
exploitation and exploration prospects and leads, drilling prospects, drilling
risks, refrac opportunities and expected results, consolidation opportunities,
marketing and trading opportunities and risks, and the Company's financial
position, stability of cash flow, debt service capabilities, capital
availability, debt repayment plans, divestiture plans, business strategy and
other plans and objectives for future operations, potential liabilities or the
expected absence thereof, the potential materiality of year 2000 compliance
expenses and the potential outcome of environmental matters, litigation or other
proceedings, are forward-looking statements. All forward-looking statements
included or incorporated by reference in this 10-K Report are based on
information available to the Company on the date hereof, and the Company assumes
no obligation to update such forward-looking statements. Although the Company
believes that the assumptions and expectations reflected in such forward-looking
statements are reasonable, it can give no assurance that such expectations will
prove to have been correct or that the Company will take any actions that may
presently be planned.

There are numerous uncertainties inherent in estimating quantities of proved oil
and gas reserves and projecting future rates of production and timing of
development expenditures, including many factors beyond the control of the
Company. See Item 2. "Properties--Oil and Gas Reserves."

Many factors may affect the Company's expectations and plans. Capital
expenditure and financing plans may change in connection with the success of
drilling activities, the general availability of capital, interest rates, and
cash flow available from operations. Cash flow available from operations may
change depending on costs of materials and services, regulatory burdens and
commodity prices. Oil and gas prices are volatile, and there are several
potentially significant adverse effects to the Company which can result if
product prices decline materially. First, lower product prices will adversely
affect the Company's cash flow and could cause the Company to (i) curtail its
capital program, (ii) borrow additional amounts under its revolving credit
agreement, or (iii) issue additional debt or equity securities. Second, lower
product prices could cause the borrowing base under the Company's bank credit
agreement to be reduced and certain covenant tests to be adversely affected.
Third, under rules promulgated by the Securities and Exchange Commission,
companies that follow the full cost accounting method are required to make
quarterly "ceiling test" calculations. Lower product prices adversely impact the
ceiling calculation. Subsequent to year end, oil prices have declined. If oil
prices are further reduced or if gas prices also decline, now or in the future,
the Company could be required to write down its oil and gas properties,
resulting in a non-cash charge against earnings.







                                       36
<PAGE>   37

Certain additional important factors that could cause actual results to differ
materially from the Company's forward-looking statements are disclosed under
"Business," "Properties," other portions of "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and elsewhere in this
10-K Report and in the Company's 8-K Report filed February 26, 1997. All
subsequent written or oral forward-looking statements attributable to the
Company or persons acting on its behalf are expressly qualified in their
entirety by the factors mentioned above or in such other sections of this 10-K
Report.






                                       37
<PAGE>   38

                              CERTAIN DEFINITIONS


The terms defined in this section are used throughout this report.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
reference to crude oil or other liquid hydrocarbons.

Bcf. Billion cubic feet of gas.

Behind-pipe reserves. Proved reserves in a formation through which production
casing has already been set in the wellbore, but from which production has not
commenced.

Boe. Barrels of oil equivalent, determined using the ratio of six Mcf of gas
(including natural gas liquids) to one Bbl of crude oil or condensate.

Btu. British thermal unit or units. One Btu is the heat required to raise the
temperature of a one pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

COPAS charge. A charge made by the operator of a well for the account of all
working interests, the payment of which constitutes reimbursement for the
operator's administrative costs attributable to operating the well.

Development location. A location on which a development well can be drilled.

Development well, development drilling. Drilling of a well within the proved
area of an oil or gas reservoir to the stratigraphic depth of a horizon known to
be productive in an attempt to recover proved undeveloped reserves.

Dry hole. A well found to be incapable of producing either oil or gas in
sufficient quantities to justify completion as an oil or gas well.

Estimated future net revenues. Revenues from production of oil and gas, net of
all production-related taxes, lease operating expenses and capital costs.

Exploitation well or exploitation drilling. Drilling of wells in areas of known
production. However, because of geologic, reservoir and other characteristics it
is possible that an exploitation well may not encounter commercial quantities of
reserves. Therefore such wells carry somewhat greater risk than development
drilling. Oil and gas reserves associated with exploitation wells are not
typically considered to be proved.

Exploratory well or exploratory drilling. A well drilled to find and produce oil
or gas in an unproved area, to find a new reservoir in a field previously found
to be productive of oil or gas in another reservoir, or to extend a known
reservoir beyond existing defined limits.







                                       38
<PAGE>   39



Farmout. An assignment of an interest in a drilling location and related
acreage, typically conditional upon the drilling of a well on that drilling
location.

Finding Cost. The capital costs associated with finding and developing oil and
gas reserves.

Gross acre. An acre in which a working interest is owned.

Gross well. A well in which a working interest is owned.

Held by production. Acreage covered by an oil and gas lease which has a
producing well on it, or which is pooled with a lease or leases having one or
more producing wells on them, so the lease is maintained in effect for the
duration of such production.

Henry Hub. The delivery point of the NYMEX gas contract, located in southern
Louisiana.

Horizontal drilling. Horizontal drilling involves deviating the angle of a
wellbore approximately 90 degrees from vertical to near horizontal in the
formation of interest. Horizontal drilling permits the wellbore to contact and
intersect a larger portion of the producing horizon than is permitted by
conventional vertical drilling techniques and can result in increased production
rates and greater ultimate recovery of hydrocarbons.

Hydraulic fracturing. A mechanical technique used to enhance productivity and
ultimate reserve recovery. Fluids and a proppant are injected into a particular
reservoir at rates and pressure sufficient to create a series of fractures or
cracks in that reservoir.

Increased density, or infill, drilling. Somewhat similar to development
drilling, increased density drilling involves wells drilled within the proved
area of an oil or gas reservoir to a zone known to be productive. However,
infill drilling generally involves an increase in well density based on
engineering and geological studies which demonstrate that the existing well
density does not adequately drain the reservoir.

Lease operating expense. All direct costs associated with and necessary to
operate a producing property.

MBbl. One thousand barrels of crude oil or other liquid hydrocarbons.

MBoe. One thousand barrels of oil equivalent.

MBtu. One thousand Btus.

Mcf. One thousand cubic feet of gas.

MMBbl. One million barrels of crude oil or other liquid hydrocarbons.

MMBoe. One million barrels of oil equivalent.







                                       39
<PAGE>   40

MMBtu. One million Btus.

MMcf. One million cubic feet of gas.

Multi-pay horizons. A well bore with more than one zone that may potentially
produce oil and/or gas.

Net acres or net wells. The sum of the working interests owned in gross acres or
gross wells.

Present value of estimated future net revenues, pretax present value at constant
prices of estimated future net revenues. Estimated future net revenues before
income taxes, discounted by a factor of ten percent per annum and with no price
or cost escalation or de-escalation in accordance with guidelines promulgated by
the Commission.

Productive well. A well that is producing or that is capable of producing oil or
gas.

Proved developed reserves. Reserves that can be expected to be recovered through
existing wells with existing equipment and operating methods.

Proved reserves. The estimated quantities of crude oil, gas and natural gas
liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions.

Proved undeveloped location. A site on which a development well can be drilled
consistent with local spacing rules for the purpose of recovering proved
reserves.

Proved undeveloped reserves. Reserves that are expected to be recovered from new
wells on undrilled acreage, or from existing wells where a relatively major
expenditure is required for recompletion.

Recompletions. Within an existing wellbore, a recompletion involves completion
for production of a formation other than those which have previously been
productive. It is the mechanism by which behind-pipe reserves become productive.

Reserve replacement costs. Total costs incurred for exploration and development,
divided by reserves added from all sources, including reserve discoveries,
extensions and improved recovery additions, net of revisions to reserve
estimates and purchases of reserves in place.

Royalty interest, overriding royalty interest. An interest in an oil and gas
property entitling the owner to a share of oil and gas production free of costs
of drilling, completion and production.

Tcf. One trillion cubic feet of gas.





                                       40
<PAGE>   41
3-D seismic projects. 3-D seismic projects involve the use of seismic
reflections to assist in mapping in three dimensions the structural and
stratigraphic aspects of certain reservoirs lending themselves to the
application of this advanced technology. Particularly when coupled with advanced
processing, interpretation, geostatistical techniques and interpretive geology,
this technology can materially reduce the risk associated with some types of
drilling.

Undeveloped acreage. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and gas regardless of whether such acreage contains proved reserves.

Waterflood. A waterflood is the injection of water into a reservoir to (i) fill
pores vacated by produced fluids or (ii) push hydrocarbons from the injector
well to another wellbore from which reserves can be produced. Waterfloods are
intended to maintain reservoir pressure, assist production and enhance reservoir
recovery rates.

Wattenberg. The geographic region in the D-J Basin located approximately 35
miles north of Denver, where the J-Sand formation is productive, as well as
adjacent areas where the Codell, Niobrara, Sussex and Shannon formations are
productive.

Wellbore extension. A wellbore extension involves deepening an existing wellbore
to a new and deeper formation.

Working interest. The operating interest which gives the owner the right to
drill, produce and conduct operating activities on the property and entitles it
to ownership of a share of production.







                                       41
<PAGE>   42

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


CONSOLIDATED BALANCE SHEETS
HS Resources, Inc.

<TABLE>
<CAPTION>
                                                                                                           December 31,
                                                                                              1997                 1996
                                                                                   ---------------      ---------------
<S>                                                                                <C>                  <C>
Assets
Current Assets
     Cash and cash equivalents                                                     $     6,907,708      $     8,764,756
     Margin deposits                                                                         3,996              575,712
     Accounts receivable
         Oil and gas sales                                                              23,052,931           22,601,396
         Trading and transportation                                                     14,366,469           17,786,206
         Trade                                                                           3,579,327            2,255,359
         Other                                                                           4,711,805            5,625,980
     Lease and well equipment inventory, at cost                                         1,424,301            1,724,944
     Prepaid expenses and other                                                            628,797              513,471
                                                                                   ---------------      ---------------
         Total current assets                                                           54,675,334           59,847,824
                                                                                   ---------------      ---------------
Oil and Gas Properties, at cost, using the full cost method
     Undeveloped acreage                                                               189,064,119           54,709,553
     Costs subject to depreciation, depletion and amortization                         951,678,001          727,411,293
     Less accumulated depreciation, depletion and amortization                        (181,205,919)        (129,940,868)
                                                                                   ---------------      ---------------
         Net oil and gas properties                                                    959,536,201          652,179,978
                                                                                   ---------------      ---------------
Gas Gathering and Transportation Facilities,
     at cost, net of accumulated depreciation of $1,322,382 and
     $1,032,224 at December 31, 1997 and 1996, respectively                              4,540,806            4,674,075
                                                                                   ---------------      ---------------
Other Assets
     Deferred charges and other, net                                                    10,254,796            8,954,781
     Office and transportation equipment and other property,
         net of accumulated depreciation of $5,083,746 and
         $3,401,739 at December 31, 1997 and 1996, respectively                          4,735,106            4,708,436
     Investment in oil and gas limited partnership                                         860,288              920,285
                                                                                   ---------------      ---------------
         Total other assets                                                             15,850,190           14,583,502
                                                                                   ---------------      ---------------
Total Assets                                                                       $ 1,034,602,531      $   731,285,379
                                                                                   ===============      ===============
</TABLE>



   The accompanying notes are an integral part of these consolidated financial
                                   statements.



                                       42
<PAGE>   43

CONSOLIDATED BALANCE SHEETS
HS Resources, Inc.



<TABLE>
<CAPTION>
                                                                                           December 31,
                                                                              1997                 1996
                                                                   ---------------      ---------------
<S>                                                                <C>                  <C>
Liabilities and Stockholders' Equity
Current Liabilities
     Accounts payable
         Trade                                                     $    18,888,306      $     9,124,831
         Revenue                                                        17,460,848            8,134,201
         Gas purchases                                                   7,854,715           13,878,187
     Accrued expenses
         Ad valorem and production taxes                                 8,432,221            7,516,095
         Interest                                                        3,691,983            3,179,627
         Other                                                           7,359,030            4,235,410
     Current portion of long-term debt                                      30,000               30,000
                                                                   ---------------      ---------------
         Total current liabilities                                      63,717,103           46,098,351
                                                                   ---------------      ---------------
Accrued Ad Valorem Taxes                                                10,606,402            9,005,922
                                                                   ---------------      ---------------
Deferred Revenue (Note 11)                                               9,872,870                   --
                                                                   ---------------      ---------------
Long-Term Oil and Gas Production Note Payable                              734,696              734,696
                                                                   ---------------      ---------------
Long-Term Bank Debt, Net of Current Portion                            412,000,000          174,000,000
                                                                   ---------------      ---------------
9 7/8% Senior Subordinated Notes,
     due 2003, net of unamortized discount of
     $346,125 and $404,625 at December 31, 1997
     and 1996, respectively                                             74,653,875           74,595,375
                                                                   ---------------      ---------------
9 1/4% Senior Subordinated Notes,
     due 2006, net of unamortized discount of
     $689,587 and $767,287 at December 31, 1997
     and 1996, respectively                                            149,310,413          149,232,713
                                                                   ---------------      ---------------
Deferred Income Taxes                                                   90,798,036           84,828,612
                                                                   ---------------      ---------------
Commitments and Contingencies (Note 10)
                                                                   ---------------      ---------------
Minority Interest in Oil and Gas Limited Partnership                      (713,200)              66,149
                                                                   ---------------      ---------------
Stockholders' Equity
     Preferred stock (Note 7)                                                   --                   --
     Common stock, $.001 par value, 30,000,000 shares
         authorized; 18,654,545 and 17,127,861 shares issued
         and outstanding at December 31, 1997 and 1996,
         respectively                                                       18,655               17,128
     Additional paid-in capital                                        183,191,380          163,114,868
     Retained earnings                                                  42,773,142           31,433,399
     Deferred compensation                                                (144,300)            (171,300)
     Treasury stock, at cost, 160,358 and 121,952 shares at
         December 31, 1997 and 1996, respectively                       (2,216,541)          (1,670,534)
                                                                   ---------------      ---------------
         Total stockholders' equity                                    223,622,336          192,723,561
                                                                   ---------------      ---------------
Total Liabilities and Stockholders' Equity                         $ 1,034,602,531      $   731,285,379
                                                                   ===============      ===============
</TABLE>



  The accompanying notes are an integral part of these consolidated financial
                                  statements.



                                       43
<PAGE>   44

CONSOLIDATED STATEMENTS OF OPERATIONS
HS Resources, Inc.

<TABLE>
<CAPTION>
                                                                     For the Years Ended December 31,
                                                               1997             1996             1995
                                                       ------------     ------------     ------------
<S>                                                    <C>              <C>              <C>
Revenues
      Oil and gas sales                                $137,251,046     $107,280,873     $ 53,394,029
      Trading and transportation                         90,061,787       46,372,707               --
      Other gas revenues                                  4,449,159        2,720,423        1,782,349
      Interest income and other                           1,942,894          582,067          163,510
                                                       ------------     ------------     ------------
         Total revenues                                 233,704,886      156,956,070       55,339,888
                                                       ------------     ------------     ------------
Expenses
      Production taxes                                    9,703,108        8,195,389        4,050,483
      Lease operating                                    24,847,903       17,691,502        9,935,809
      Cost of trading and transportation                 88,402,012       45,699,154               --
      Depreciation, depletion and amortization           53,240,787       42,334,882       26,608,885
      General and administrative                          7,986,999        5,642,393        4,075,581
      Interest                                           31,204,621       22,935,840       10,218,555
                                                       ------------     ------------     ------------
         Total expenses                                 215,385,430      142,499,160       54,889,313
                                                       ------------     ------------     ------------
Income before Provision for Income Taxes                 18,319,456       14,456,910          450,575
Provision for Income Taxes                                6,979,713        5,508,083          176,419
                                                       ------------     ------------     ------------
Net Income                                             $ 11,339,743     $  8,948,827     $    274,156
                                                       ============     ============     ============
Basic earnings per share                               $       0.66     $       0.63     $       0.03
                                                       ============     ============     ============
Diluted earnings per share                             $       0.64     $       0.61     $       0.02
                                                       ============     ============     ============
Weighted average number of common shares
      outstanding                                        17,119,000       14,119,000       10,893,000
                                                       ============     ============     ============
Weighted average number of common shares
      outstanding assuming dilution                      17,593,000       14,552,000       11,439,000
                                                       ============     ============     ============
</TABLE>



   The accompanying notes are an integral part of these consolidated financial
                                   statements.






                                       44
<PAGE>   45

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
HS Resources, Inc.


<TABLE>
<CAPTION>
                                                                     For the Years Ended December 31, 1997, 1996, and 1995

                                     Common Stock      Additional                                               Treasury Stock
                                ---------------------   Paid-In           Retained         Deferred       --------------------------
                                  Shares     Amount     Capital           Earnings       Compensation      Shares           Amount
                                ----------  --------- -------------     ------------     ------------      --------      -----------
<S>                             <C>        <C>        <C>               <C>              <C>               <C>          <C>
Balance, December 31, 1994      10,948,680 $  10,949  $ 97,720,356      $  22,210,416     $       --       (40,313)     $  (584,109)
  Purchase of
    treasury stock                      --        --            --                 --             --       (63,700)        (846,625)
  Transfer of treasury
    stock to 401(k) Plan                --        --         3,328                 --             --        26,536          358,287
  Exercise of options
    by issuance of
    treasury stock,
    including income
    tax benefit                         --        --        (5,776)                --             --         2,400           33,144
  Net income                            --        --            --            274,156             --            --               --
                                ---------- ---------  ------------      -------------     ----------      --------      -----------
Balance, December 31, 1995      10,948,680    10,949    97,717,908         22,484,572             --       (75,077)      (1,039,303)
                                ---------- ---------  ------------      -------------     ----------      --------      -----------
  Purchase of treasury
    stock                               --        --            --                 --             --      (113,817)      (1,460,490)
  Transfer of treasury
    stock to 401(k)
    Plan                                --        --       (53,961)                --             --        20,025          246,708
  Issuance of common stock
    for Tide West
    Merger                       6,169,181     6,169    65,231,025                 --             --            --               --
  Exercise of options by
    issuance of treasury
    stock, including
    income tax benefit                  --        --        48,606                 --             --        46,917          582,551
  Issuance of restricted
    stock                           10,000        10       171,290                 --       (171,300)           --               --
  Net income                            --        --            --          8,948,827             --            --               --
                                ---------- ---------  ------------      -------------     ----------      --------      -----------
Balance, December 31, 1996      17,127,861    17,128   163,114,868         31,433,399       (171,300)     (121,952)      (1,670,534)
                                ---------- ---------  ------------      -------------     ----------      --------      -----------
  Purchase of treasury stock            --        --            --                 --             --      (101,247)      (1,398,669)
  Transfer of treasury
    stock to 40l(k)
    Plan                                --        --       (68,011)                --             --        35,894          485,287
  Issuance of common stock
    for Amoco Acquisition        1,200,000     1,200    19,998,800                 --             --            --               --
  Exercise of options by
    issuance of treasury
    stock, including
    income tax benefit                  --        --       (34,355)                --             --        26,947          367,375
  Issuance of restricted stock       2,500         3        44,997                 --        (45,000)           --               --
  Amortization of deferred
    compensation                        --        --            --                 --         72,000            --               --
  Issuance of common stock          12,203        12       135,393                 --             --            --               --
  Exercise of warrants and
    options                        311,981       312          (312)                --             --            --               --
  Net income                            --        --            --         11,339,743             --            --               --
                                ---------- ---------  ------------      -------------     ----------      --------      -----------
Balance, December 31, 1997      18,654,545 $  18,655  $183,191,380      $  42,773,142     $ (144,300)     (160,358)     $(2,216,541)
                                ========== =========  ============      =============     ==========      ========      ===========
</TABLE>






   The accompanying notes are an integral part of these consolidated financial
                                   statements.



                                       45
<PAGE>   46

CONSOLIDATED STATEMENTS OF CASH FLOWS
HS Resources, Inc.

<TABLE>
<CAPTION>
                                                                                                    For the Years Ended December 31,
                                                                                         1997               1996               1995
                                                                                -------------      -------------      -------------
<S>                                                                             <C>                <C>                <C>
Cash Flows from Operating Activities
     Net income                                                                 $  11,339,743      $   8,948,827      $     274,156
     Adjustments to reconcile net income to net cash
             provided by operating activities
          Depreciation, depletion and amortization                                 53,240,787         42,334,882         26,608,885
          Amortization of deferred charges and debenture issue costs                1,830,552          1,082,988            615,368
          Transfer of treasury stock to 401(k) Plan                                   417,276            192,747            378,141
          Gain on sale of fixed assets                                                     --           (118,649)           (52,545)
          Deferred income tax provision                                             5,969,424          5,135,328            171,482
          Decrease (increase) in accounts and notes receivable                      2,558,409        (21,784,122)         1,113,301
          Increase in accounts payable and accrued expenses                         7,947,122         16,157,951          2,596,066
          Increase (decrease) in deferred revenue, net                              9,872,870                 --         (1,206,154)
          Other                                                                       842,595            301,197            680,242
                                                                                -------------      -------------      -------------
     Net cash provided by operating activities                                     94,018,778         52,251,149         31,178,942
                                                                                -------------      -------------      -------------
Cash Flows from Investing Activities
     Exploration, development and leasehold costs                                 (75,137,151)       (50,626,521)       (62,094,658)
     Purchase of unproved and proved properties                                  (299,086,755)      (129,982,687)                --
     Cash payment for the Tide West Merger, net of cash acquired                           --        (85,125,084)                --
     Gas gathering and transportation facilities additions                           (156,889)           (53,597)          (649,469)
     Other property additions                                                      (1,712,246)        (1,056,547)          (141,881)
     Proceeds from the sale of oil and gas properties                              35,602,632          9,678,851                 --
     Proceeds from the sale of fixed assets and other property                             --            157,043            419,116
     Increase (decrease) in property related payables                              11,272,110              8,130         (2,817,069)
                                                                                -------------      -------------      -------------
     Net cash used in investing activities                                       (329,218,299)      (257,000,412)       (65,283,961)
                                                                                -------------      -------------      -------------
Cash Flows from Financing Activities
     Proceeds from debt                                                           337,000,000        536,316,596         48,400,000
     Repayments of debt                                                           (99,000,000)      (315,258,900)       (14,000,000)
     Tide West Merger costs                                                                --         (2,623,792)                --
     Debt issuance costs                                                           (2,947,934)        (4,328,056)                --
     Issuance of common stock                                                         135,405                 --                 --
     Exercise of options                                                              333,020            631,157             10,842
     Purchase of treasury stock                                                    (1,398,669)        (1,460,490)          (846,625)
     Minority interest, net                                                          (779,349)           120,923                 --
                                                                                -------------      -------------      -------------
     Net cash provided by financing activities                                    233,342,473        213,397,438         33,564,217
                                                                                -------------      -------------      -------------
Net (Decrease) Increase In Cash and Cash Equivalents                               (1,857,048)         8,648,175           (540,802)
     Cash and cash equivalents, beginning of year                                   8,764,756            116,581            657,383
                                                                                -------------      -------------      -------------
     Cash and cash equivalents, end of year                                     $   6,907,708      $   8,764,756      $     116,581
                                                                                =============      =============      =============
Supplemental Cash Flow Disclosure
     Interest paid, net of capitalized interest                                 $  28,730,596      $  20,078,634      $   9,072,167
     Cash paid for income taxes, net of reimbursements                          $    (413,297)     $     418,296      $          --
     Schedule of noncash investing and financing activities:
          Exchange of  properties in Amoco Acquisition                          $  23,000,000      $          --      $          --
          Common stock issued in Amoco Acquisition                              $  20,000,000      $          --      $          --
                                                                                =============      =============      =============
</TABLE>





  The accompanying notes are an integral part of these consolidated financial
                                  statements.




                                       46
<PAGE>   47

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
HS Resources, Inc.


NOTE 1 - THE COMPANY

HS Resources, Inc., a Delaware corporation, (the "Company") was organized in
January 1987. The Company, directly or through subsidiaries, acquires, develops,
and exploits oil and gas properties. The Company's primary properties are
located in the Denver-Julesburg ("D-J") Basin, the Anadarko and Arkoma Basins of
the Mid-Continent, the onshore area of the Texas-Louisiana Gulf Coast and the
Northern Rocky Mountains. The Company, through its wholly owned subsidiary HS
Energy Services, Inc. ("HSES"), markets its own gas production, markets gas
owned by third parties and actively trades both physical and financial positions
in the gas commodities market.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

OIL AND GAS PROPERTIES The Company accounts for its oil and gas activities using
the full cost method of accounting. Under the full cost method of accounting,
all costs of exploration for and development of oil and gas reserves, including
costs of surrendered and abandoned leaseholds, delay lease rentals, dry hole
costs, geological and geophysical costs and direct overhead related to
exploration and development activities are capitalized. Capitalized payroll and
other internal costs include salaries and related fringe benefits paid to
employees directly engaged in the acquisition, exploration, and development of
oil and gas properties, as well as all other directly identifiable internal
costs associated with these activities, such as rentals, utilities, and
insurance. Payroll and other internal costs associated with production,
operation, and general corporate activities are expensed in the period incurred.
Future development, site restoration, dismantlement, and abandonment costs, net
of salvage values, are estimated on a property-by-property basis based on
prevailing prices and are amortized to expense, along with the capitalized costs
discussed above, using the unit-of-production method based upon production and
estimates of proved reserve quantities. Accumulated depreciation, depletion, and
amortization is recorded on the balance sheets as a reduction to property,
plant, and equipment costs. No gains or losses are recognized upon the sale or
other disposition of oil and gas properties unless a significant portion of the
reserves are sold.

Capitalized costs associated with undeveloped properties are excluded from
amortization until a determination has been made as to the existence of proved
reserves or an impairment has occurred. At December 31, 1997 and 1996, the
Company excluded costs aggregating $189.1 million and $54.7 million,
respectively, from capitalized costs being amortized. Of the costs excluded at
December 31, 1997, $147.5 million were incurred in 1997, $27.3 million in 1996,
$3.2 million in 1995, $11 million in 1994, and $0.1 million in 1990. The Company
capitalizes interest related to its undeveloped properties. During 1997, 1996,
and 1995, the Company capitalized $4.9 million, $3.3 million, and $2.0 million
of interest, respectively.

Net capitalized costs of oil and gas properties less related deferred income
taxes may not exceed an amount equal to the present value discounted at 10% of
estimated future net revenue from proved oil and gas reserves plus the lower of
costs or estimated fair market value of unproved properties (the "full cost
ceiling"). Should capitalized costs exceed the full cost ceiling, an impairment
would be provided. The full cost ceiling may be particularly sensitive to
changes in the near term in pricing







                                       47
<PAGE>   48

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


and production rates. The above limitation is applied on a quarterly basis using
current prices at the end of the quarter.

INCOME TAXES The Company follows the liability method of accounting for income
taxes as prescribed by SFAS 109. Accordingly, deferred tax provisions or
benefits are recognized in the financial statements for the change in deferred
tax liabilities or assets during each year. The deferred liabilities or assets
represent taxes payable or refundable in future years, as measured by the
provisions of enacted tax laws, or as a result of temporary differences between
the bases of assets and liabilities for financial reporting and tax reporting
purposes. Such differences relate mainly to depreciable and depletable
properties and intangible drilling costs.

CASH EQUIVALENTS Cash and cash equivalents include cash on hand, amounts held in
banks, and highly liquid investments purchased with an original maturity of
three months or less.

FINANCIAL INSTRUMENTS The Company engages in price and location risk management
activities for both hedging and trading purposes. Activities for hedging
purposes are entered into by the Company to manage its exposure to price and
location risks in the marketing of its oil and gas production and, in the case
of its marketing activities, third party gas. Gains and losses on hedging
positions are deferred and recognized in the period the underlying physical
transactions occur in "oil and gas sales" (for company-owned production) and
"trading and transportation revenues" (for third party gas). Activities for
trading purposes are accounted for using the mark-to-market method. Under this
method, changes in the market value of outstanding financial instruments are
recognized as a gain or loss in the period of change on a net basis in "trading
and transportation revenues." The market prices used to value these transactions
reflect management's best estimate considering various factors including closing
exchange and over-the-counter quotations, time value and volatility factors
underlying the commitments. The values are adjusted to reflect the potential
impact of liquidating the Company's position in an orderly manner over a
reasonable period of time under present market conditions.

EARNINGS PER SHARE In February 1997 the Financial Accounting Standards Board
issued SFAS No. 128, "Earnings Per Share." This new statement provides
computation, presentation and disclosure requirements for earnings per share
("EPS"). The new standard was effective for the Company for fiscal 1997 and all
prior periods have been retroactively adjusted. Basic EPS is computed based on
the monthly weighted average number of common shares outstanding during the
periods. The weighted average number of common shares used in computing basic
EPS was 17,119,000, 14,119,000 and 10,893,000 for 1997, 1996 and 1995,
respectively. Diluted EPS is computed based on the monthly weighted average
number of common shares outstanding during the periods and the assumed exercise
of dilutive common stock equivalents (stock options and warrants) using the
treasury stock method. Dilutive common stock equivalents assumed to have been
exercised totaled 474,000, 433,000 and 546,000 for 1997, 1996 and 1995,
respectively.







                                       48
<PAGE>   49

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.



ACCRUED AD VALOREM TAXES The Company classifies as current ad valorem taxes
payable within one year. Other ad valorem taxes are classified as non-current
because the required payment dates are not within one year.

DEFERRED CHARGES Legal and accounting fees, printing costs and other expenses
associated with the issuance of the Company's debt have been capitalized and are
being amortized over the remaining term of the debt.

GAS GATHERING AND TRANSPORTATION FACILITIES Depreciation of gas gathering and
transportation facilities is provided using the straight-line method over
estimated useful lives of 20 years.

OFFICE AND TRANSPORTATION EQUIPMENT Depreciation of office and transportation
equipment is provided using the straight-line method over estimated useful
lives which range from three to ten years.

GAS IMBALANCES Gas imbalances are accounted for under the sales method whereby
revenues are recognized based on actual production sold. At December 31, 1997,
the Company's gas balancing position was approximately 733,000 Mcf overproduced.

USE OF ESTIMATES The preparation of financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.

NEW ACCOUNTING STANDARDS In June 1997, the Financial Accounting Standards Board
issued Statement of Financial Accounting Standards No. 130 ("SFAS 130"),
Reporting Comprehensive Income, and SFAS No. 131 ("SFAS 131"), Disclosure about
Segments of an Enterprise and Related Information, which are required to be
adopted for fiscal years beginning after December 15, 1997. SFAS 130 establishes
standards for the reporting and display of comprehensive income and its
components in a full set of general-purpose financial statements. This statement
requires that all items which are recognized under accounting standards as
components of comprehensive income be reported in a financial statement that is
displayed with the same prominence as other financial statements.
Reclassification of financial statements for earlier periods provided for
comparative purposes is required. SFAS 131 requires a public company to report
selected information about its reportable operating segments. Operating segments
are components of an enterprise for which discrete financial information is
available. The Company expects to adopt SFAS 130 and SFAS 131 for the year ended
December 31, 1998.







                                       49
<PAGE>   50

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


NOTE 3 - ACQUISITIONS AND MERGER

Effective December 1, 1997, the Company acquired all of the producing and
non-producing properties in the Wattenberg field area of the D-J Basin from
Amoco Production Company ("Amoco") (the "Amoco Acquisition") for $290 million in
cash, 1,200,000 shares of common stock valued at $20 million and the transfer to
Amoco of certain producing Mid-Continent properties valued at $23 million. The
Amoco properties contain estimated proved reserves of 70.2 MMBoe at December 31,
1997 and include interests in 2,068 wells, of which 804 were operated by Amoco.
The Amoco Acquisition was accounted for using the purchase method of accounting
and the Company began consolidating the results of operations on the closing
date of December 15, 1997.

In March and June 1996, the Company acquired all of the D-J Basin oil and gas
properties of Basin Exploration, Inc. ("Basin") (the "Basin Acquisition") for
aggregate cash consideration of $125.5 million. The Basin Acquisition included a
total of 850 gross wells with approximately 35 MMBoe of net proved reserves at
December 31, 1995, and approximately 5,500 Boe of net daily production. The
Basin Acquisition was accounted for using the purchase method of accounting and
the Company began consolidating the results of operations as of March and June,
1996.

On June 17, 1996, the Company completed the merger of Tide West Oil Company
("Tide West") into a wholly owned subsidiary of the Company (the "Merger").
Pursuant to the Merger, Tide West shareholders received 0.6295 shares (totaling
6,169,181 shares in aggregate) of the Company's common stock and $8.704 cash for
each outstanding share of Tide West common stock, for an aggregate consideration
of $187.7 million. The Merger added 1,259 gross wells, approximately 39.1 MMBoe
of net proved reserves at December 31, 1995, and 9,985 Boe of daily production
net to the Company. Tide West was an independent oil and gas company with
principal operations in portions of the Anadarko and Arkoma geologic basins
located within Oklahoma, Texas and Arkansas, as well as additional operations
located in southern Oklahoma, Texas and New Mexico. The Company accounted for
the Merger using the purchase method of accounting and began consolidating Tide
West's results as of June 17, 1996.


NOTE 4 - PRO FORMA STATEMENTS (UNAUDITED)

The following table sets forth the condensed unaudited pro forma operating
results of the Company for the twelve months ended December 31, 1997, 1996 and
1995. The condensed pro forma operating results assume that the Amoco
Acquisition had occurred on January 1, 1996, and that both the Basin Acquisition
and the Merger had occurred on January 1, 1995 (see Note 3). The condensed pro
forma results are not necessarily indicative of the results of operations had
the Amoco Acquisition been consummated on January 1, 1996, and the Basin
Acquisition and the Merger been consummated on January 1, 1995, and may not
necessarily be indicative of future performance.



                                       50
<PAGE>   51

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


<TABLE>
<CAPTION>
                                                                                       Twelve Months Ended December 31,
                                                                                                    (Unaudited)
                                                                           --------------------------------------------------
                                                                                    1997              1996              1995
                                                                           -------------     -------------     -------------
<S>                                                                        <C>               <C>               <C>
Revenues                                                                   $ 271,213,301     $ 269,413,538     $ 203,407,171
Net income (loss)                                                          $   5,820,980     $   7,445,679     $  (2,446,727)
Diluted earnings per share                                                 $        0.31     $        0.40     $       (0.14)
Weighted average number of common shares outstanding assuming dilution        18,740,000        18,608,000        17,600,000
</TABLE>


NOTE 5 - RISK MANAGEMENT

The Company uses financial instruments to reduce its exposure to market
fluctuations in the price and transportation cost of oil and gas. The Company's
general strategy is to hedge price and location risk with swap, collar, floor
and ceiling arrangements. In order to minimize risk, to the maximum extent
possible, the Company hedges its production back to the wellhead. In addition to
hedging activities, the Company is engaged in using the financial markets to
capture trading margins. The Company has established policies with respect to
open positions which limit its exposure to market risk and requires daily
reporting to management of the potential financial exposure resulting from both
hedging and trading activities.

Hedging Activities Activities for hedging purposes are entered into by the
Company to manage its exposure to price and location risks in the marketing of
its oil and gas production and, in the case of its marketing activities, third
party gas. Gains and losses on hedging positions are recognized in the period
during which the underlying transactions occur and are booked in "oil and gas
sales" (for company owned production) and "trading and transportation revenues"
(for third party gas).

The Company's general strategy is to hedge price and location risk with swap,
collar, floor and ceiling arrangements. As a part of its risk management
program, the Company generally enters into hedges for delivery into one of the
two pipelines located near its producing regions, Panhandle Eastern Pipeline
Company ("PEPL") or Colorado Interstate Gas Company ("CIG"), or at the New York
Mercantile Exchange ("NYMEX") prices settled at the Henry Hub. With respect to
the NYMEX hedged volumes that exceed the Company's Gulf Coast volumes, the
Company usually hedges basis to its producing regions at such time as the
Company deems advantageous. Currently, the Company holds hedge swap positions as
follows:





                                       51
<PAGE>   52
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.

<TABLE>
<CAPTION>
                           Average Daily
                              Volume        Settlement           Price
        Time Period           (MMBtu)        Location         (per MMBtu)
     ------------------    -------------    ----------        -----------
<S>                         <C>            <C>                <C>
     January-March 1998        10,000         CIG               $2.21
                               50,000         PEPL              $2.53
                               25,000        NYMEX              $2.54
     April-October 1998        25,000         CIG               $1.66
                               20,000         PEPL              $2.03
                               16,000        NYMEX              $2.22
</TABLE>


The Company has hedged approximately 24% of its expected 1998 oil production at
$19.52 per Bbl. Additionally, with respect to the hedging of third party gas,
the Company has hedged 12.5 Bcf through December 1998 with offsetting physical
positions at settlement prices which are based upon NYMEX future prices or other
published indices.

Trading Activities The Company engages in the trading of various energy related
financial instruments which require payments to (or receipt of payments from)
counterparties based on the differential between a fixed and variable price for
the commodity, swap or other contractual arrangement. Company policy requires
that, within defined trading limits, financial instrument purchase and sales
contracts be balanced in terms of contract volumes and the timing of performance
and delivery obligations. As of December 31, 1997, all material open positions
were balanced with an offsetting position.

The Company accounts for these activities using the mark-to-market method of
accounting. During 1997, gains of $453,821 were recognized in connection with
these activities and are included in "trading and transportation revenues."

Credit Risk While notional amounts are used to express the volume of various
derivative financial instruments, the amounts potentially subject to credit
risk, in the event of nonperformance by the third parties, are substantially
smaller. Counterparties to the swap, collar, floor and ceiling arrangements
discussed above are investment grade financial institutions. Accordingly, the
Company does not anticipate any material impact to its financial position or
results of operations as a result of nonperformance by the third parties to
financial instruments related to hedging activities or trading activities.




                                       52
<PAGE>   53
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


NOTE 6 - LONG-TERM DEBT

Debt at December 31, 1997 and 1996 consists of the following:

<TABLE>
<CAPTION>
                                                         1997               1996
                                                    -------------      -------------
<S>                                                 <C>                <C>
Long-term bank and other debt
Bank debt                                           $ 412,000,000      $ 174,000,000
Other debt                                                764,696            764,696
                                                    -------------      -------------
                                                      412,764,696        174,764,696
Less-current portion                                      (30,000)           (30,000)
                                                    -------------      -------------
Long-term bank debt and other debt,
     net of current portion                         $ 412,734,696      $ 174,734,696
                                                    =============      =============
9 7/8% Senior Subordinated notes,
     due 2003, net of unamortized discount of
     $346,125 and $404,625 at December 31, 1997
     and 1996, respectively                         $  74,653,875      $  74,595,375
                                                    =============      =============
9 1/4% Senior Subordinated notes,
     due 2006, net of unamortized discount of
     $689,587 and $767,287 at December 31, 1997
     and 1996, respectively                         $ 149,310,413      $ 149,232,713
                                                    =============      =============
</TABLE>


BANK DEBT On June 7, 1996, the Company entered into a $180 million revolving
senior term credit facility with The Chase Manhattan Bank, as Agent (the "Chase
Facility"), which was amended to $350 million on June 14, 1996. On December 15,
1997, as a result of the Amoco Acquisition, the Chase Facility was further
amended to increase the maximum credit amount and borrowing base to $450 million
and revise the interest rates payable thereunder to the Base Rate plus 0% to
0.625% or LIBOR plus 0.75% to 1.625%. Under the terms of the Chase Facility, no
principal payments are required until December 15, 2002, assuming the Company
maintains a borrowing base sufficient to support the outstanding loan balance.
The borrowing base is based on the underlying value of the Company's oil and gas
properties.

During the second quarter of 1995, the Company entered into an interest rate
exchange agreement with a financial institution to hedge its interest rate on
$40 million of the Company's borrowings at 7.76% through May 2002. Under the
terms of the agreement, the difference between the Company's fixed rate of 7.76%
and the three-month LIBOR rate plus 1.125% is received or paid by the Company.
The Company, through the Merger with Tide West, was assigned interest rate
exchange agreements with two financial institutions to hedge its interest rate
on a total of $40 million of the Company's borrowings at rates ranging from
6.16% to 7.32% for 1997 through 1999. Under the terms of the agreement, the
difference between the Company's fixed rate and the three month LIBOR rate is
received or paid by the Company.



                                       53
<PAGE>   54
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


SENIOR SUBORDINATED NOTES In November 1993, the Company issued $75 million of
its 9 7/8% senior subordinated notes due in 2003. The notes were priced to yield
10% and the Company received net proceeds of $71.9 million after underwriting
commissions and offering costs. The proceeds of the notes were used to repay all
outstanding indebtedness under the Company's bank credit facility and for
working capital purposes. The notes pay interest semi-annually on June 1 and
December 1. Under the terms of the notes, there are no sinking fund requirements
and the Company is limited as to certain additional indebtedness beyond its
existing credit facility if certain financial covenants are not maintained.

In November 1996, the Company issued $150 million of its 9 1/4% senior
subordinated notes due in 2006. The notes pay interest semi-annually on May 15
and November 15. The notes were priced to yield 9.33% and the Company received
net proceeds of $144.9 million after underwriting commissions and offering
costs. The proceeds of the notes were used to replace with fixed rate term debt
a portion of the outstanding indebtedness under the Company's bank credit
facility.

CARRYING VALUE At December 31, 1997 and 1996, the carrying amount of the
Company's 9 7/8% senior subordinated notes was $74.7 million and $74.6 million
and the estimated fair value was $77.3 million and $78.3 million, respectively.
At December 31, 1997 and 1996, the carrying amount of the 9 1/4% senior
subordinated notes was $149.3 million and $149.2 million and the estimated fair
value was $153.4 million and $149.2 million, respectively. The fair value is
estimated based on the quoted market prices for the same or similar issues, or
on the current rates offered to the Company for debt of the same remaining
maturity.

Based on borrowing rates available for bank loans with similar collateral, the
fair values of the borrowings under the bank debt and other debt at December 31,
1997, are estimated to be their carrying value of $412 million and $0.8 million,
respectively.

NOTE 7 - STOCKHOLDERS' EQUITY

SERIES A CONVERTIBLE PARTICIPATING PREFERRED STOCK The Company has authorized
15,000,000 shares of $.001 par value Series A convertible preferred stock, of
which no shares are currently issued or outstanding. The stock has a stated
value of $13.50 and a liquidation preference of $1.00 per share.

SERIES A JUNIOR PREFERRED STOCK In February 1996 the Company authorized 300,000
shares of Series A junior preferred stock. The stock shall be issuable upon
exercise of rights (the "Rights") issued pursuant to the agreement dated as of
February 28, 1996, between the Company and Harris Trust Company of California,
as Rights Agent (the "Rights Agreement"). The Rights Agreement was designed to
protect the Company's shareholders in the event of takeover action that would
deny them the full value of their investment (the "Rights Plan").



                                       54
<PAGE>   55

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


Terms of the Rights Plan provide for a dividend distribution of one right for
each share of Company common stock to holders of record at the close of business
on March 14, 1996. The Rights will automatically become part of and traded with
existing and future shares of the Company's common stock. The Rights will become
exercisable only in the event, with certain exceptions, an acquiring party
accumulates 15% or more of HS Resources, Inc.'s voting stock, or if a party
announces an offer to acquire 30% or more of the Company's voting stock. No
separate rights certificates will be issued until at least one of these
thresholds is met. The Rights will expire on March 14, 2006.

Under the Rights Plan, if any person or group becomes the beneficial owner of 15
percent or more of the Company's common stock, or in the event of a merger or
other business combination, each right will entitle the holder other than the
acquiring party to purchase either Company stock or shares in an "acquiring
entity" at a 50 percent discount of the then current market value. HS Resources
will be entitled to redeem the rights at $0.01 per right at any time prior to
such time that a person or group acquires a 15 percent position in the Company's
voting stock.

WARRANTS The Company had 6,000 warrants outstanding and exercisable at $6.67 per
share as of December 31, 1997 and 746,262 warrants outstanding and exercisable
at $8.98 per share as of December 31, 1996 and 1995.

RESTRICTED STOCK In connection with the issuance of 12,500 shares of restricted
stock in 1996 and 1997, the Company recorded $216,300 of deferred compensation
representing the difference between the deemed fair value for accounting
purposes and the stock price as determined by the Company at the date of grant.
This amount is presented as a reduction of stockholders' equity and will be
amortized over the three year vesting period of the related stock. Subsequent to
December 31, 1997, the Company issued 23,645 shares of restricted stock. The
Company will record $332,449 of deferred compensation in 1998 and will amortize
such amount over the four year vesting period of the stock.



                                       55
<PAGE>   56

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.



NOTE 8 - PROVISION FOR INCOME TAXES

The provision for income taxes consists of the following:

<TABLE>
<CAPTION>
                        1997           1996           1995
                  ----------     ----------     ----------
<S>               <C>            <C>            <C>
Current:
      Federal     $  200,000     $  250,000     $       --
      State          700,000         50,000             --
                  ----------     ----------     ----------
                     900,000        300,000             --
                  ----------     ----------     ----------
Deferred:
      Federal      5,425,466      4,647,633        157,434
      State          654,247        560,450         18,985
                  ----------     ----------     ----------
                   6,079,713      5,208,083        176,419
                  ----------     ----------     ----------
                  $6,979,713     $5,508,083     $  176,419
                  ==========     ==========     ==========
</TABLE>


The deferred income tax expense, during the years ended December 31, 1997, 1996,
and 1995 results from the following:

<TABLE>
<CAPTION>
                                                  1997              1996              1995
                                             ------------      ------------      ------------
<S>                                          <C>               <C>               <C>
Type of temporary difference
Alternative minimum tax                      $     50,000      $   (250,000)     $         --
Depreciation, depletion and amortization       (3,051,216)       (2,797,220)           32,871
Intangible drilling costs                      18,239,155         1,212,361         4,873,778
Sales of properties                            (5,966,696)        1,424,878        (8,268,363)
Operating loss carryforwards                   (3,191,530)        5,618,064         3,533,383
                                             ------------      ------------      ------------
Deferred tax provision                       $  6,079,713      $  5,208,083      $    171,669
                                             ============      ============      ============
</TABLE>




                                       56
<PAGE>   57

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.



The components of the net deferred tax liability as of December 31, 1997 and
1996 are as follows:

<TABLE>
<CAPTION>
                                                      1997               1996
                                             -------------      -------------
<S>                                          <C>                <C>
Deferred tax liabilities
Depreciation and basis difference            $ 106,017,612      $  96,901,658
                                             -------------      -------------
Deferred tax liability                         106,017,612         96,901,658

Deferred tax assets
Tax effect of regular net operating loss        11,962,286          8,770,756
Alternative minimum tax credit                     937,000            982,000
Statutory depletion carryforwards                2,320,290          2,320,290
Investment tax credit carryforwards                 94,480            168,772
All other                                               --                 --
                                             -------------      -------------
                                                15,314,056         12,241,818
Valuation allowance                                (94,480)          (168,772)
                                             -------------      -------------
Deferred tax assets, net                        15,219,576         12,073,046
                                             -------------      -------------
Net deferred tax liability                   $  90,798,036      $  84,828,612
                                             =============      =============
</TABLE>


In 1996, the Company recorded $58,117,144 of deferred tax liabilities and
$2,027,400 of deferred tax assets in connection with its merger with Tide West.

The effective tax rate during 1997, 1996 and 1995 differs from the statutory
rate of 35% principally because of the effects of state income taxes, net of
federal tax benefit.

The Company has net tax operating loss carryforwards aggregating approximately
$31.4 million available at December 31, 1997, to offset future taxable income.
These carryforwards, if not previously utilized, expire in 2004 through 2011.
Included in these carryforwards are approximately $3.4 million of losses
acquired in the 1996 merger with Tide West. The Company's ability to utilize
these losses is subject to the "ownership change" limitation. The ownership
change rules will limit to approximately $0.8 million annually the amount of
Tide West's losses that can be used.

The Company has an alternative minimum tax ("AMT") credit carryforward of
approximately $937,000. AMT credits can be carried forward indefinitely and may
only be used to reduce regular tax liabilities in future years when regular tax
payable exceeds AMT payable. The Company also has a percentage depletion
carryforward of approximately $6 million which can be used to reduce taxable
income in the future and is not subject to expiration. Finally, the Company has
investment tax credit carryforwards of approximately $94,000 which will expire
in 1998 and 1999. Due to the uncertainty that the investment tax credits will be
applied against future tax liabilities, the Company has not given effect for the
benefit of these amounts in calculating its deferred tax liability.



                                       57
<PAGE>   58

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.



NOTE 9 - EMPLOYEE BENEFIT PLANS

401(K) AND PROFIT SHARING PLANS Effective June 30, 1989, the Company adopted two
qualified defined contribution plans, the HS Resources, Inc. Employee Investment
401(k) Plan (the "401(k) Plan") and the HS Resources, Inc. Profit Sharing Plan
(the "Profit Sharing Plan"). Employees are eligible to participate in both plans
after one year of service. Under the 401(k) Plan, participants may make regular
pretax contributions of up to 10% of their compensation (up to a maximum of
$9,500) and receive matching contributions from the Company in an amount
determined by the Board of Directors. All contributions to the 401(k) Plan are
vested 100% upon participation. Under the Profit Sharing Plan only the Company
can make contributions. Company contributions are determined by the Board of
Directors and are vested to participants over five years of service. Company
contributions to both plans are included in general and administrative expenses
in the accompanying statements of operations.

At December 31, 1997, the Company accrued approximately $650,000 for the 1997
contribution to the 401(k) Plan. Contributions to the plans were $417,276 and
$211,596 in 1996 and 1995, respectively.

STOCK OPTION PLAN In 1987, the Company's shareholders approved the 1987 Stock
Incentive Plan (the "1987 Plan") whereby directors, officers, key employees, and
consultants of the Company were entitled to receive incentive stock options,
non-qualified stock options, stock appreciation rights, and restricted stock.
Options granted pursuant to the 1987 Plan were exercisable for no more than ten
years at no less than fair market value (85% of fair market value in the case of
non-qualified stock options) on the date of the grant. In April 1997, the 1987
Plan expired; however, of the 1.5 million shares of Company stock authorized to
be issued under the 1987 Plan, approximately 824,000 remain outstanding as of
December 31, 1997.

In May 1997, the 1997 Performance and Equity Incentive Plan (the "1997 Plan")
was approved by the Company's stockholders. The 1997 Plan provides for the award
of benefits of various types to salaried employees and directors of the Company
and its affiliates. These include stock options, stock appreciation rights,
restricted shares of Company stock, performance shares, performance-based cash
awards and other performance-based stock awards. One million shares of the
Company's stock are subject to the 1997 Plan. The Company accounts for this plan
under Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to
Employees, under which no compensation cost was recognized during 1997, 1996 and
1995. During 1996, the Company implemented SFAS No. 123, Accounting for Stock
Based Compensation. Had compensation cost for these plans been determined
consistent with FAS 123, net of the effect of forfeitures and tax, the Company
would have recorded compensation costs of $298,000, $66,000 and $19,000 in 1997,
1996 and 1995, respectively.



                                       58
<PAGE>   59

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.



The following table summarizes activity with respect to outstanding stock
options for the years 1997, 1996 and 1995:

<TABLE>
<CAPTION>
                                                   Weighted Average
                                        Shares       Option Price
                                       -------     ----------------
<S>                                    <C>          <C>
Outstanding at December 31, 1994
     (565,070 shares exercisable)      780,170      $  11.25
     Granted                            14,000         17.00
     Exercised                          (2,400)        12.00
     Forfeited                         (47,333)        19.83
                                       -------      ---------
Outstanding at December 31, 1995
     (613,369 shares exercisable)      744,437         10.81
     Granted                            94,000         12.37
     Exercised                         (46,917)        12.00
     Forfeited                         (18,000)        23.92
                                       -------      ---------
Outstanding at December 31, 1996
     (626,670 shares exercisable)      773,520         10.63
     Granted                           163,000         14.60
     Exercised                         (40,650)         9.23
     Forfeited                          (7,000)        14.14
                                       -------      ---------
Outstanding at December 31, 1997
     (635,370 shares exercisable)      888,870      $  11.39
                                       =======      ========
</TABLE>



Of the 888,870 options outstanding at December 31, 1997, 635,370 options are
fully vested and have exercise prices between $6.67 and $25.00, with a weighted
average exercise price of $10.15 and a weighted average remaining contractual
life of 3.1 years. The remaining 253,500 options have exercise prices between
$10.13 and $25, with a weighted average exercise price of $14.51 and a weighted
average remaining contractual life of 6.3 years.



                                       59
<PAGE>   60

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


The fair value of each option grant is estimated on the date of grant using the
Black-Scholes option pricing model with the following weighted-average
assumptions used for grants in 1997, 1996 and 1995, respectively: risk free
interest rates ranging from 5.5% to 5.8%; expected dividend yield of 0%;
expected life of 6 years; expected volatility of 39%, 67% and 67%, respectively.

NOTE 10 - COMMITMENTS AND CONTINGENCIES

ENVIRONMENTAL MATTERS In May 1995, the Company was named by the Environmental
Protection Agency (the "EPA") pursuant to a Resource Conservation and Recovery
Act administrative order as one of two respondents in addition to the
owner/operator of an oilfield production water evaporation facility. The order
requires that work be performed to abate a perceived endangerment to wildlife,
the environment or public welfare. The Company and other non-operator
respondents are working together with the EPA to develop characterization
studies of the site, and have caused the facility to be permanently closed.
Based on the Company's current knowledge and its expectation of proportionate
reimbursement from other parties who utilized the facility, the Company does not
believe that its share of the reclamation costs will have a material impact on
its financial condition or results of operations. By agreement with other
contributing parties, the Company is currently paying approximately 50% of the
costs associated with the project, but after recovery from additional liable
parties, the Company's percentage share of overall costs may be reduced to as
little as 40%. The Company's share of total costs associated with the project,
at the 50% level of participation, are currently estimated to range from $1 to
$2 million over three years. The Company has recorded environmental remediation
liabilities of approximately $1.4 million at December 31, 1997.

LITIGATION

On July 22, 1997, Chenier Exploration, Inc. ("Chenier") brought suit against the
Company in the United States District Court for the Eastern District of Texas
(Chenier Exploration, Inc. v. HS Resources, Inc., Civil Action No. 1:97-CV-399)
seeking damages and certain preliminary relief arising out of the termination of
an Exploration and Development Agreement ("Agreement") between Chenier and the
Company. The Agreement called for, among other things, cooperation between the
companies in the identification and development of oil and gas prospects in the
Gulf Coast regions of Louisiana and Texas. On August 22, 1997, the Court denied
Chenier's requests for preliminary relief and granted the Company's request that
the remaining disputes between Chenier and the Company be resolved in an
arbitration conducted under the auspices of the American Arbitration Association
("AAA") and entitled In re HS Resources, Inc. and Chenier Exploration, Inc., AAA
Arbitration No. 77-180-00171-97.

Chenier asserted that the Company breached express and implied provisions of the
Agreement in connection with its termination of that Agreement, that the Company
acted in bad faith in connection with the Agreement and that the Company
wrongfully interfered with employment and other existing and prospective
agreements involving Chenier in connection with the termination of the
Agreement. The Company denied each of these claims and believed it had
substantial legal defenses to each of the claims, and vigorously defended
against them. These claims were addressed in an arbitration






                                       60
<PAGE>   61

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


hearing which commenced on February 2, 1998, and ended February 17, 1998. For a
discussion of the final decision, see Note 16 of the Notes to Consolidated
Financial Statements.

Additionally, the Company is subject to minor lawsuits incidental to operations
in the oil and gas industry. The Company believes it has meritorious defenses to
all lawsuits in which it is a defendant and will vigorously defend against them.
The resolution of such lawsuits, regardless of the outcome, will not have a
material adverse effect on the Company's financial position or results of
operations.

OPERATING LEASES The Company is obligated under noncancelable operating leases
for office space and certain equipment. Total rental expense related to these
leases was $2,382,498, $1,653,378 and $1,263,930 for December 31, 1997, 1996 and
1995, respectively. Future minimum lease payments as of December 31, 1997 are:





<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------------------------------
<S>                                                <C>
1998                                               $    2,230,770
1999                                                    1,817,336
2000                                                    1,844,635
2001                                                    1,855,767
2002                                                    1,470,347
Thereafter                                              1,073,839
                                                   --------------
Total minimum lease payments                       $   10,292,694
                                                   ==============
</TABLE>


NOTE 11 - OTHER GAS REVENUES

The Company and its subsidiaries continue to enter into transactions designed to
monetize the Company's Section 29 tax credits. In eleven separate transactions,
the first of which was entered into on December 1, 1995, the Company has sold to
unaffiliated third parties its right, title and interest in certain of its oil
and gas leases and mineral interests. The sale will enable the third parties to
earn tax credits associated with future oil and gas production. The Company
reserved a volumetric production payment that entitles it to 100% of the net
cash flows from the properties. In the fourth quarter of 1997, the Company
received approximately $10.6 million in prepaid tax credits. The Company
recorded the proceeds as deferred revenue and is amortizing the amount to gas
revenues as the gas is produced and the credits are generated. As of December
31, 1997, the Company had amortized approximately $0.7 million of prepaid tax
credits. The Company recognized approximately $4.4 million and $2.7 million of
other gas revenues associated with the tax credits during the years ended
December 31, 1997 and 1996, respectively.



                                       61
<PAGE>   62

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


NOTE 12 - OIL AND GAS ACTIVITIES

MAJOR PURCHASERS In 1997, sales to HSES, Duke Energy Field Service and Amoco
accounted for approximately $31,850,000, $28,704,000 and $23,286,000 or 23.2%,
20.9% and 17.0% of total oil and gas sales, respectively. In 1996, sales to
Amoco and Panenergy accounted for approximately $29,300,000 and $22,800,000 or
27.3% and 21.2%, of total oil and gas sales, respectively. In 1995, sales to
Amoco and K N Marketing, Inc. accounted for approximately $24,600,000 and
$6,120,000 or 46% and 11.5%, of total oil and gas sales, respectively.

COSTS INCURRED  Costs incurred in oil and gas operations and the related
depreciation, depletion, and amortization per equivalent unit-of-production are
as follows:


<TABLE>
<CAPTION>
                                                                            Year Ended December 31,
                                                  1997                   1996                  1995
                                    ------------------        ---------------       ---------------
<S>                                 <C>                       <C>                   <C>
Property acquisition costs
      Unproved                      $      131,261,839        $    35,227,230       $     4,342,722
      Proved                        $      167,824,916        $   338,813,429       $    25,014,756
                                    ------------------        ---------------       ---------------
Exploration costs                   $       12,856,148        $     2,100,119       $     2,747,920
                                    ------------------        ---------------       ---------------
Development costs                   $       46,678,371        $    37,818,991       $    29,989,260
                                    ------------------        ---------------       ---------------
Depreciation, depletion and
      amortization                  $       51,265,051        $    40,590,801       $    25,292,193
                                    ------------------        ---------------       ---------------
Depreciation, depletion and
      amortization per equivalent
      unit-of-production            $             5.54        $          5.33      $           4.97
                                    ==================        ===============       ===============
</TABLE>


NOTE 13 - SUMMARY OF GUARANTEES ON 9 1/4% SENIOR SUBORDINATED NOTES

In November 1996, the Company issued $150 million of its 9 1/4% senior
subordinated notes due in 2006. The notes are general, unsecured obligations of
the Company, subordinated in right of payment to all existing and any future
senior indebtedness of the Company. The notes rank pari passu with existing and
any future senior subordinated indebtedness and senior to any future
subordinated indebtedness of the Company. The notes are fully and
unconditionally guaranteed, jointly and severally, on an unsecured, senior
subordinated basis by two of the Company's subsidiaries, Orion Acquisition, Inc.
and HSRTW, Inc. (the "Subsidiary Guarantors").







                                       62
<PAGE>   63

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.



Sections 13 and 15 (d) of the Securities Exchange Act of 1934 require
presentation of the following supplemental condensed consolidating financial
statements of the Subsidiary Guarantors. Separate complete financial statements
of the respective Subsidiary Guarantors are not material to investors. There are
no significant contractual restrictions on distributions from each of the
Subsidiary Guarantors to the Company.

Investments in subsidiaries are accounted for by the parent under the equity
method for purposes of the supplemental condensed consolidated financial
statement presentation. Under this method, investments are recorded at cost and
adjusted for the parent company's ownership share of the subsidiaries'
cumulative results of operations. In addition, investments increase in the
amount of contributions to subsidiaries and decrease in the amount of
distributions from subsidiaries. The elimination entries eliminate the equity
method investment in subsidiaries and equity in earnings of subsidiaries,
intercompany payables and receivables and other transactions between
subsidiaries including contributions and distributions.



                                       63
<PAGE>   64

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


                     CONDENSED CONSOLIDATING BALANCE SHEETS


                                December 31, 1997

<TABLE>
<CAPTION>
                                                               ASSETS
                                                                                       Non-
                                                      Subsidiary Guarantors         Guarantor       Elimination
                                  HSR              HSRTW             Orion         Subsidiaries        Entries        Consolidated
                             -------------     -------------     -------------    --------------  ---------------     -------------
<S>                          <C>                 <C>                 <C>                <C>                <C>                 <C>

Cash and cash
 equivalents                 $   3,530,198     $     159,181     $          --    $  3,218,329    $            --     $   6,907,708
Intercompany
 receivables                    50,135,345        62,297,182        44,082,701      31,757,711       (188,272,939)               --
Other current
 assets                         17,104,097         6,666,991         5,070,687      20,069,162         (1,143,311)       47,767,626
                             -------------     -------------     -------------    ------------    ---------------     -------------
 Total current
  assets                        70,769,640        69,123,354        49,153,388      55,045,202       (189,416,250)       54,675,334
                             -------------     -------------     -------------    ------------    ---------------     -------------
Oil and gas
 properties, net               658,415,237       181,907,170       119,213,794              --                 --       959,536,201
Gas gathering and
 transportation
 facilities, net                        --                --                --       4,540,806                 --         4,540,806
Deferred charges
 and other, net                  9,935,628             9,058           308,410           1,700                 --        10,254,796
Office and
 transportation
 equipment and other
 property, net                   3,140,578         1,344,174                --         250,354                 --         4,735,106
Investments in
 subsidiaries and
 other investments             339,641,386         4,023,421                --         860,288       (343,664,807)          860,288
                           ---------------     -------------     -------------    ------------    ---------------   ---------------
 Total assets              $ 1,081,902,469     $ 256,407,177     $ 168,675,592    $ 60,698,350    $  (533,081,057)  $ 1,034,602,531
                           ===============     =============     =============    ============    ===============   ===============


                                      LIABILITIES, STOCKHOLDERS' EQUITY AND PARTNERS' CAPITAL

Current liabilities        $    43,210,893     $   9,418,848     $      44,184    $ 12,116,491     $   (1,103,313)  $    63,687,103
Current portion of
 long-term debt                     30,000                --                --              --                 --            30,000
Intercompany payables          138,137,807         4,410,000        35,252,159      10,472,973       (188,272,939)               --
Long-term bank
 debt and other debt,
 net of current portion        412,734,696                --                --              --                 --       412,734,696
9 7/8% subordinated
 notes, due 2003                74,653,875                --                --              --                 --        74,653,875
9 1/4% subordinated
 notes, due 2006               149,310,413                --                --              --                 --       149,310,413
Other noncurrent
 liabilities                    20,479,272                --                --              --                 --        20,479,272
Deferred income taxes           19,723,177        61,231,841         2,563,645       7,279,373                 --        90,798,036
Minority interest                       --                --                --          23,596           (736,796)         (713,200)
Stockholders' equity
 and partners'
 capital                       223,622,336       181,346,488       130,815,604      30,805,917       (342,968,009)      223,622,336
                           ---------------     -------------     -------------    ------------     --------------   ---------------
 Total liabilities,
  stockholders' equity
  and partners' capital    $ 1,081,902,469     $ 256,407,177     $ 168,675,592    $ 60,698,350     $ (533,081,057)  $ 1,034,602,531
                           ===============     =============     =============    ============     ==============   ===============
</TABLE>






                                       64
<PAGE>   65

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.

                CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

                     Twelve Months Ended December 31, 1997
<TABLE>
<CAPTION>

                                                                                          Non-
                                                       Subsidiary Guarantors           Guarantor       Elimination
                                        HSR            HSRTW           Orion         Subsidiaries        Entries        Consolidated
                                   ------------    ------------    ------------      -------------    -------------     ------------
<S>                                <C>               <C>              <C>              <C>             <C>               <C>
Revenues
 Oil and gas sales                 $ 54,409,889    $ 33,692,171    $ 11,602,694       $ 36,648,062    $    898,230      $137,251,046
 Trading and transportation           4,060,027      16,078,296              --        108,042,290     (38,118,826)       90,061,787
 Other revenues                       5,561,898         548,146              --            538,709        (256,700)        6,392,053
                                   ------------    ------------    ------------       ------------    ------------      ------------
  Total revenues                     64,031,814      50,318,613      11,602,694        145,229,061     (37,477,296)      233,704,886
                                   ------------    ------------    ------------       ------------    ------------      ------------
Expenses
 Production taxes and lease
  operating                          11,287,571       8,128,667       3,894,294         11,240,479              --        34,551,011
 Cost of trading and
  transportation                      4,122,294      15,252,113              --        106,248,199     (37,220,594)       88,402,012
 Depreciation, depletion and
  amortization                       22,928,530      14,403,058       4,493,234         11,415,965              --        53,240,787
 General and administrative           3,566,995       3,043,262         350,000          1,026,742              --         7,986,999
 Interest                            27,378,156       3,712,484          45,817            324,866        (256,702)       31,204,621
                                   ------------    ------------    ------------       ------------    ------------      ------------
  Total expenses                     69,283,546      44,539,584       8,783,345        130,256,251     (37,477,296)      215,385,430
                                   ------------    ------------    ------------       ------------    ------------      ------------

Income (loss) before provision
 for income taxes                    (5,251,732)      5,779,029       2,819,349         14,972,810              --        18,319,456
Provision (benefit) for income
 taxes                               (2,000,910)      2,966,047       1,074,172          4,940,404              --         6,979,713
                                   ------------    ------------    ------------       ------------    ------------      ------------
                                     (3,250,822)      2,812,982       1,745,177         10,032,406              --        11,339,743
Equity in earnings of
 subsidiaries                        11,340,759       3,249,806              --                 --     (14,590,565)               --
                                   ------------    ------------    ------------       ------------    ------------      ------------
Net income                         $  8,089,937    $  6,062,788    $  1,745,177       $ 10,032,406    $(14,590,565)     $ 11,339,743
                                   ============    ============    ============       ============    ============      ============
</TABLE>




                                       65
<PAGE>   66

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.



                 CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

                      Twelve Months Ended December 31, 1997

<TABLE>
<CAPTION>
                                                                                        Non-
                                                      Subsidiary Guarantors          Guarantor     Elimination
                                     HSR             HSRTW             Orion       Subsidiaries      Entries          Consolidated
                                -------------    -------------    -------------   -------------    -------------      -------------
<S>                             <C>              <C>              <C>             <C>               <C>               <C>
Cash flows provided by
 (used in) operating
 activities                     $ 109,140,819    $ (33,082,135)   $     621,409   $  17,338,685    $          --      $  94,018,778
                                -------------    -------------    -------------   -------------    -------------      -------------

Cash flows from investing
 activities
Exploration, development
 and leasehold costs              (57,581,031)      (7,807,448)      (1,821,454)     (7,927,218)              --        (75,137,151)
Purchase of proved and
 unproved properties             (296,070,291)      (3,016,464)              --              --               --       (299,086,755)
Contributions to
 subsidiaries                      (1,200,045)      18,728,474               --              --      (17,528,429)                --
Other                               9,989,411       25,661,873               --       9,354,323               --         45,005,607
                                -------------    -------------    -------------   -------------    -------------      -------------
      Net cash used in
       (provided by)
       investing
       activities                (344,861,956)      33,566,435       (1,821,454)      1,427,105      (17,528,429)      (329,218,299)
                                -------------    -------------    -------------   -------------    -------------      -------------

Cash flows from financing
 activities
Proceeds from debt                337,000,000               --               --              --               --        337,000,000
Repayments of debt                (99,000,000)              --               --              --               --        (99,000,000)
Contributions from equity
 holders                                   --               --        1,200,045     (18,728,474)      17,528,429                 --
Other                              (3,878,178)        (779,349)              --              --               --         (4,657,527)
                                -------------    -------------    -------------   -------------    -------------      -------------
      Net cash provided
       by (used in)
       financing activities       234,121,822         (779,349)       1,200,045     (18,728,474)      17,528,429        233,342,473
                                -------------    -------------    -------------   -------------    -------------      -------------

Net increase (decrease) in
 cash and cash equivalents         (1,599,315)        (295,049)              --          37,316               --         (1,857,048)
Cash and cash equivalents,
 beginning of the year              5,129,513          454,230               --       3,181,013               --          8,764,756
                                -------------    -------------    -------------   -------------    -------------      -------------

Cash and cash equivalents,
 end of the period              $   3,530,198    $     159,181    $          --   $   3,218,329    $          --      $   6,907,708
                                =============    =============    =============   =============    =============      =============
</TABLE>


Certain non-cash transactions have taken place between HSR and its subsidiaries
related to the equity contributions. Accordingly, these transactions are not
reflected in the statements of cash flows.


                                       66
<PAGE>   67

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


NOTE 14 - SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

OIL AND GAS NET RESERVES The following unaudited tables set forth the estimated
quantities of net proved oil and gas reserves for the Company and the changes in
total proved reserves as of December 31, 1997, 1996 and 1995. All such reserves
are located in the United States. The amounts as of December 31, 1997, 1996 and
1995, were prepared by the Company and substantially all were reviewed by either
Williamson Petroleum Consultants, Inc. or by Netherland, Sewell & Associates,
Inc., each an independent petroleum engineering consulting firm.







                                       67
<PAGE>   68

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


ANALYSIS OF CHANGES IN PROVED RESERVES


<TABLE>
<CAPTION>
                                                         Oil               Gas
                                                   -----------------------------------
                                                                       (Thousands of
                                                        (Barrels)        Cubic Feet)
Proved developed and undeveloped reserves
--------------------------------------------------------------------------------------
<S>                                                    <C>              <C>
Balance, December 31, 1994                             18,301,220       265,277,800
     Revision of previous estimates                    (1,293,758)       (1,363,766)
     Extensions, discoveries and other additions        1,127,196        11,851,415
     Production                                        (1,581,586)      (21,049,484)
     Purchases of reserves in place                     3,124,140        45,353,782
     Sales of reserves in place                           (89,452)       (1,292,347)
                                                       ----------       -----------
Balance, December 31, 1995                             19,587,760       298,777,400
     Revision of previous estimates                         4,868          (880,400)
     Extensions, discoveries and other additions        1,424,288        41,786,934
     Production                                        (1,923,435)      (34,163,010)
     Purchases of reserves in place                    15,648,402       351,707,690
     Sales of reserves in place                          (127,503)      (12,807,314)
                                                       ----------       -----------
Balance, December 31, 1996                             34,614,380       644,421,300
     Revision of previous estimates                    (2,726,993)      (36,809,862)
     Extensions, discoveries and other additions        2,098,560        42,623,250
     Production                                        (2,399,743)      (41,125,200)
     Purchases of reserves in place                    14,839,796       332,793,612
     Sales of reserves in place                        (1,067,900)      (62,049,000)
                                                       ----------       -----------
Balance, December 31, 1997                             45,358,100       879,854,100
                                                       ==========       ===========
Proved developed reserves
     December 31, 1995                                 11,557,200       219,262,100
                                                       ==========       ===========
     December 31, 1996                                 23,111,490       508,923,100
                                                       ==========       ===========
     December 31, 1997                                 26,027,500       611,198,400
                                                       ==========       ===========
</TABLE>



                                       68
<PAGE>   69

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


STANDARDIZED MEASURE The standardized measure of discounted future net cash
flows, and changes therein related to proved oil and gas reserves are as
follows:


<TABLE>
<CAPTION>
                                                                                                  Year Ended December 31,
                                                                           1997                 1996                 1995
                                                                ---------------      ---------------      ---------------
<S>                                                             <C>                  <C>                  <C>
Future cash inflows                                             $ 2,771,498,000      $ 3,045,480,000      $   857,074,500
Future production costs                                            (681,825,000)        (646,925,700)        (219,076,680)
Future development costs                                           (360,007,000)        (170,708,400)        (105,043,800)
                                                                ---------------      ---------------      ---------------
Undiscounted future pre-tax cash flows                            1,729,666,000        2,227,845,900          532,954,020
Undiscounted future income taxes                                   (410,680,162)        (619,110,885)        (129,776,984)
                                                                ---------------      ---------------      ---------------
Undiscounted future pre-tax cash flows,
     net of future income taxes                                   1,318,985,838        1,608,735,015          403,177,036
10% discount factor                                                (689,534,976)        (790,717,180)        (203,918,587)
                                                                ---------------      ---------------      ---------------
Standardized measure of discounted future net cash flows        $   629,450,862      $   818,017,835      $   199,258,449
                                                                ---------------      ---------------      ---------------
Discounted future pre-tax cash flows excluding income taxes     $   822,466,600      $ 1,130,923,000      $   257,044,900
                                                                ===============      ===============      ===============
</TABLE>


The estimate of future income taxes is based on the future net cash flows from
proved reserves adjusted for the tax basis of the oil and gas properties. For
standardized measure purposes, future income taxes are estimated using the
"year-by-year" method. However, for ceiling test purposes, future income taxes
are estimated using the "short-cut" method.



                                       69
<PAGE>   70

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


The following are the principal sources of change in the standardized measure of
discounted future net cash flows:



<TABLE>
<CAPTION>
                                                                               Year Ended December 31,
                                                            1997               1996               1995
                                                   -------------      -------------      -------------
<S>                                                <C>                <C>                <C>
Standardized measure of discounted future
     net cash flows, beginning of the year         $ 818,017,835      $ 199,258,449      $ 194,253,301
Sales and transfers of oil and gas produced,
     net of production costs                        (101,796,457)       (80,450,583)       (38,528,808)
Sales of reserves in place                           (63,971,600)       (14,892,716)        (1,338,530)
Net changes in prices and production costs:
     On beginning of year reserves                  (464,696,728)       281,677,346          3,996,469
     On reserves purchased during the year                    --        200,295,822                 --
Extensions, discoveries and improved recovery,
     less related costs                               60,509,682         80,749,964         11,194,559
Changes in future development costs                  (22,474,120)        (2,088,801)       (14,744,408)
Development costs incurred during the period
     that reduced future development costs            43,489,081         32,335,836         33,402,053
Revisions of previous quantity estimates             (46,871,761)        (1,679,406)        (6,918,919)
Purchase of reserves in place                        265,063,849        345,252,515         36,213,033
Accretion of discount                                113,282,652         25,704,490         23,033,140
Net change in income taxes                           121,793,142       (255,118,714)       (21,708,352)
Changes in production rates (timing) and other       (92,894,713)         6,973,633        (19,595,089)
                                                   -------------      -------------      -------------
Standardized measure of discounted future
     net cash flows, end of the year               $ 629,450,862      $ 818,017,835      $ 199,258,449
                                                   =============      =============      =============
</TABLE>



                                       70
<PAGE>   71

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


Estimated future cash inflows are computed by applying year-end prices of oil
and gas to year-end quantities of proved reserves. Future price changes are
considered only to the extent provided by contractual arrangements. Estimated
future development and production costs are determined by estimating the
expenditures to be incurred in developing and producing the proved oil and gas
reserves held by the Company as of the end of the year, based on year-end costs
and assuming continuation of existing economic conditions. Estimated future
income tax expenses are calculated by applying year-end statutory tax rates
(adjusted for permanent differences) to estimated future pretax net cash flows
related to proved oil and gas reserves, less the tax basis of the properties
involved. No deductions were made for general overhead, depreciation and other
indirect costs. The average year-end prices used in the projections were
$16.38/Bbl of oil and $2.31/Mcf of gas at December 31, 1997, $24.92/Bbl of oil
and $3.39/Mcf of gas at December 31, 1996 and $18.59/Bbl of oil and $1.65/Mcf of
gas at December 31, 1995.

These estimates were determined in accordance with SFAS 69. Because of
unpredictable variances in expenses and capital forecasts, crude oil and gas
price changes, and the fact that the basis for such estimates vary
significantly, management believes that the usefulness of these projections of
cash flow is limited. Estimates of future net cash flows do not represent
management's assessment of future profitability or future cash flow to the
Company. Management's investment and operating decisions may be based upon
reserve estimates that include price, cost and production assumptions which are
different from those used here.

Applying current costs and prices and a 10% standard discount rate allows for
comparability but does not convey absolute value. The discounted amounts arrived
at are only one measure of financial quantification of proved reserves.
Reservoir engineering is a process of making educated estimates of underground
accumulations of oil and gas and the amounts and timing of recovery thereof,
which cannot be measured in an exact way. The accuracy of any reserve estimate
is a function of the quality of available data and of engineering and geological
interpretation and judgment. Accordingly, reserve estimates are often materially
different from the quantities of oil and gas which are ultimately recovered.
Future development of the properties in which the Company has an interest,
including additional drilling activities, production results from wells not yet
producing, and additional production results from currently producing wells, may
provide information which justifies revisions, either upward or downward, of
reserve estimates. Such adjustments may be material.



                                       71
<PAGE>   72

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.


NOTE 15 - QUARTERLY FINANCIAL DATA (UNAUDITED)

The Company's quarterly results of operations are summarized as follows (in
thousands, except per share data):


<TABLE>
<CAPTION>
                                                                                1997
                                      Mar. 31     June 30      Sept. 30      Dec. 31
                                     --------     --------     --------      --------
<S>                                  <C>          <C>          <C>           <C>
Operating revenues                   $ 65,959     $ 50,137     $ 49,249      $ 66,417
Operating expenses                     49,741       39,639       37,587        49,227
                                     --------     --------     --------      --------
Operating income                       16,218       10,498       11,662        17,190
                                     --------     --------     --------      --------
Net income                           $  4,367     $  1,161     $  1,563      $  4,249
                                     --------     --------     --------      --------
Diluted earnings per share           $   0.25     $   0.07     $   0.09      $   0.24
                                     ========     ========     ========      ========
</TABLE>

<TABLE>
<CAPTION>
                                                                                 1996
                                      Mar. 31      June 30      Sept. 30      Dec. 31
                                     --------     --------     --------      --------
<S>                                  <C>          <C>          <C>           <C>
Operating revenues                   $ 14,154     $ 26,767     $ 47,566      $ 67,888
Operating expenses                      9,999       18,553       36,649        48,721
                                     --------     --------     --------      --------
Operating income                        4,155        8,214       10,917        19,167
                                     --------     --------     --------      --------
Net income                           $    191     $  1,645     $  1,357      $  5,756
                                     --------     --------     --------      --------
Diluted earnings per share               0.02     $   0.14     $   0.08      $   0.33
                                     ========     ========     ========      ========
</TABLE>


<TABLE>
<CAPTION>
                                                                                 1995
                                       Mar. 31     June 30      Sept. 30      Dec. 31
                                     --------     --------     --------      --------
<S>                                  <C>          <C>          <C>           <C>
Operating revenues                   $ 15,737     $ 14,810     $ 11,921      $ 12,709
Operating expenses                     11,204       10,982        9,131         9,279
                                     --------     --------     --------      --------
Operating income                        4,533        3,828        2,790         3,430
                                     --------     --------     --------      --------
Net income (loss)                    $    640     $    180     $   (383)     $   (163)
                                     --------     --------     --------      --------
Diluted earnings per share           $   0.06     $   0.02     $  (0.03)     $  (0.01)
                                     ========     ========     ========      ========
</TABLE>



NOTE 16 - SUBSEQUENT EVENT (UNAUDITED)

On March 26, 1998, the arbitrator in the Chenier litigation (See Note 10) issued
a final award in favor of the Company denying each of Chenier's claims for
damages.


                                       72
<PAGE>   73
Report of Independent Public Accountants


To the Stockholders of HS Resources, Inc.:

     We have audited the accompanying consolidated balance sheets of HS
Resources, Inc. (a Delaware corporation) and subsidiaries as of December 31,
1997 and 1996, and the related consolidated statements of operations,
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 1997. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.

     We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.

     In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of HS Resources, Inc. and
subsidiaries as of December 31, 1997 and 1996, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1997, in conformity with generally accepted accounting principles.


ARTHUR ANDERSEN LLP


Denver, Colorado


February 20, 1998



                                       73
<PAGE>   74

Item 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
          FINANCIAL DISCLOSURE


         None.

                                    PART III

Items 10-13, Inclusive:

     These items have been omitted in accordance with the instructions of Form
10-K. Pursuant to Regulation 14A of the Securities Exchange Act, the Registrant
will file with the Commission on or before April 30, 1997, a definitive proxy
statement which will include information with respect to the election of
directors.



                                       74
<PAGE>   75

                                    PART IV

Item 14.         EXHIBITS

         (a)  Exhibits.

3.1        Amended and Restated Certificate of Incorporation of the Company.
           (Incorporated herein by reference to Exhibit 3.1 to the Company's
           Registration Statement on Form S-1, No. 33-52774, filed October 2,
           1992.)

3.2        Third Amended and Restated Bylaws of the Company adopted December 16,
           1996. (Incorporated by reference to Exhibit 3.2 to the Company's
           Registration Statement on Form S-4, No 333-19433, filed January 8,
           1997.)

4.1        Form of Indenture dated December 1, 1993, entered into between the
           Company and the Trustee. (Incorporated by reference to Exhibit 4.7 to
           Amendment No. 3 to the Company's Registration Statement on Form S-3,
           No. 33-70354, filed November 23, 1993.)

4.2        Indenture dated November 27, 1996, among the Company, Orion
           Acquisition, Inc., HSRTW, Inc., and Harris Trust and Savings Bank as
           Trustee. (Incorporated by reference to Exhibit 4.2 to the Company's
           Registration Statement on Form S-4, No 333-19433, filed January 8,
           1997.)

4.3        First Supplemental Indenture dated November 25, 1996 among the
           Company, Orion Acquisition, Inc., HSRTW, Inc., and Harris Trust and
           Savings Bank as Trustee. (Incorporated by reference to Exhibit 4.3 to
           the Company's Registration Statement on Form S-4, No 333-19433, filed
           January 8, 1997.)

10.1       1987 Stock Incentive Plan, as amended December 2, 1996. (Incorporated
           by reference to Exhibit 10.5 to the Company's Quarterly Report on
           Form 10-Q for the quarter ended March 31, 1997, filed May 15, 1997.)

10.2       Common Stock Purchase Warrant dated July 12, 1990 by the Company to
           James E. Duffy. (Incorporated by reference to Exhibit 10.5 to the
           Form 8, Second Amendment to Form 10, filed April 8, 1991.)

10.3       HS Resources, Inc. Rule 701 Compensatory Benefit Plan. (Incorporated
           by reference to Exhibit 10.5.2 to the Form 8, Second Amendment to
           Form 10, filed April 8, 1991.)

10.4       1992 Directors' Stock Option Plan. (Incorporated by reference to
           Exhibit 10.10 to Amendment No. 1 to the Company's Registration
           Statement on Form S-1, No. 33-52774, filed November 9, 1992.)

10.4.1     1993 Directors' Stock Option Plan. (Incorporated by reference to
           Exhibit 10.8.1 to the Company's Annual Report on Form 10-K for the
           fiscal year ended December 31, 1993, filed March 31, 1994 (as amended
           by Form 10-K/A-1 on April 8, 1994.))

10.5       Form of Indemnification Agreement for Directors of the Company.
           (Incorporated by reference to Exhibit 10.16 to the Company's Annual
           Report on Form 10-K for the fiscal year ended December 31, 1995,
           filed March 25, 1996.)



                                       75
<PAGE>   76

10.6       Lease Agreement dated October 6, 1993, between the Company and JMB
           Group Trust IV and Endowment and Foundation Realty, Ltd. -- JMB III
           for the premises at One Maritime Plaza, San Francisco, California.
           (Incorporated by reference to Exhibit 10.13 to the Company's Annual
           Report on Form 10-K for the fiscal year ended December 31, 1993,
           filed March 31, 1994 (as amended by Form 10-K/A-1 on April 8, 1994.))

10.7       Lease Agreement dated March 28, 1994, between the Company and 1999
           Broadway Partnership for the premises at 1999 Broadway, Denver,
           Colorado. (Incorporated by reference to Exhibit 10.15 to the
           Company's Quarterly Report on Form 10-Q for the quarter ended June
           30, 1994, filed August 12, 1994.)

10.8       Interest Exchange Agreement between The Chase Manhattan Bank, N.A.
           and the Company dated May 9, 1995. (Incorporated by reference to
           Exhibit 10.19 to the Company's Quarterly Report on Form 10-Q for the
           quarter ended June 30, 1995, filed August 14, 1995.)

10.9       Amended and Restated Agreement and Plan of Merger, dated as of April
           29, 1996, among the Company, HSR Acquisition, Inc. and Tide West Oil
           Co. (Incorporated by reference as Annex A to Amendment No. 2 to the
           Company's Registration Statement on Form S-4, No. 333-01991, filed on
           May 2, 1996.)

10.10      Agreement for Purchase and Sale of Assets, dated as of February 24,
           1996, among the Company, Basin Exploration, Inc. ("Basin") and Orion
           Acquisition, Inc. ("Orion"). (Incorporated by reference to Exhibit
           2.3 to the Company's Form 8-K, filed March 12, 1996.)

10.11      Agreement for Purchase and Sale of Assets [Wattenberg], dated as of
           February 24, 1996, among the Company, Orion and Basin. (Incorporated
           by reference to Exhibit A to the Company's Schedule 13D relating to
           Basin Exploration, Inc., filed on March 6, 1996.)

10.12      Purchase and Sale Agreement, dated December 1, 1995, between the
           Company and Wattenberg Gas Investments, LLC. (Incorporated by
           reference to Exhibit 10.26 to the Company's Annual Report on Form
           10-K for the fiscal year ended December 31, 1995, filed March 25,
           1996.)

10.13      Rights Agreement, dated as of February 28, 1996, between the Company
           and Harris Trust Company of California as Rights Agent. (Incorporated
           by reference to Exhibit 1 to the Company's Form 8-A, filed March 11,
           1996.)

10.14      Purchase and Sale Agreement dated March 25, 1996, between Orion, the
           Company and Wattenberg Resources Land, L.L.C. (Incorporated by
           reference to Exhibit 10.28 to the Company's Quarterly Report on Form
           10-Q for the quarter ended March 31, 1996, filed May 15, 1996.)

10.15      Credit Agreement, dated as of June 7, 1996, among the Company and The
           Chase Manhattan Bank, N.A. ("Chase"), as agent of the Banks signatory
           thereto. (Incorporated by reference to the Company's Quarterly Report
           on Form 10-Q for the quarter ended June 30, 1996, filed August 14,
           1996.)

10.16      Amended and Restated Credit Agreement dated as of June 14, 1996,
           among the Company, Chase as agent, and the Banks signatory thereto.
           (Incorporated by reference to Exhibit 10.21 to the Company's
           Quarterly Report on Form 10-Q for the quarter ended June 30, 1996,
           filed August 14, 1996.)



                                       76
<PAGE>   77

10.17      First Amendment to Amended and Restated Credit Agreement dated as of
           June 17, 1996, by and among the Company and Chase in its individual
           capacity and as agent for the Lenders. (Incorporated by reference to
           Exhibit 10.22 to the Company's Quarterly Report on Form 10-Q for the
           quarter ended June 30, 1996, filed August 14, 1996.)

10.18      Second Amendment to Amended and Restated Credit Agreement dated as of
           November 27, 1996 among the Company and Chase in its individual
           capacity and as agent for the Lenders. (Incorporated by reference to
           Exhibit 10.22 to the Company's Registration Statement on Form S-4, No
           333-19433, filed January 8, 1997.)

10.19      Assignment of Liens and Amendment of Amended, Restated and
           Consolidated Mortgage, Assignment of Production, Security Agreement
           and Financing Statement, dated June 14, 1996, among Chase (Assignor),
           Chase (Assignee) and the Company. (Incorporated by reference to
           Exhibit 10.23 to the Company's Quarterly Report on Form 10-Q for the
           quarter ended June 30, 1996, filed August 14, 1996.)

10.20      Guaranty Agreement by HSR Acquisition, Inc. in favor of Chase, as
           Agent, dated June 14, 1996. (Incorporated by reference to Exhibit
           10.24 to the Company's Quarterly Report on Form 10-Q for the quarter
           ended June 30, 1996, filed August 14, 1996.)

10.21      Guaranty Agreement by Orion in favor of Chase, as Agent, dated June
           14, 1996. (Incorporated by reference to Exhibit 10.25 to the
           Company's Quarterly Report on Form 10-Q for the quarter ended June
           30, 1996, filed August 14, 1996.)

10.22      First Amendment to Guaranty Agreement dated as of June 17, 1996, by
           and among Orion and Chase, in its individual capacity and as agent
           for the Lenders. (Incorporated by reference to Exhibit 10.26 to the
           Company's Quarterly Report on Form 10-Q for the quarter ended June
           30, 1996, filed August 14, 1996.)

10.23      First Amendment to Guaranty Agreement dated as of June 17, 1996, by
           and among HSRTW, Inc. (formerly HSR Acquisition, Inc.) and Chase, in
           its individual capacity and as agent for the Lenders. (Incorporated
           by reference to Exhibit 10.27 to the Company's Quarterly Report on
           Form 10-Q for the quarter ended June 30, 1996, filed August 14,
           1996.)

10.24      Third Amendment and Supplement to Amended, Restated and Consolidated
           Mortgage, Assignment of Production, Security Agreement and Financing
           Statement, dated as of July 15, 1996, by and between the Company and
           Chase. (Incorporated by reference to Exhibit 10.28 to the Company's
           Quarterly Report on Form 10-Q for the quarter ended June 30, 1996,
           filed August 14, 1996.)

10.25      Hedging Agreement between Chase and the Company dated May 1, 1996.
           (Incorporated by reference to Exhibit 10.29 to the Company's
           Quarterly Report on Form 10-Q for the quarter ended June 30, 1996,
           filed August 14, 1996.)

10.26      Hedging Agreement between Chase and the Company dated May 1, 1996.
           (Incorporated by reference to Exhibit 10.30 to the Company's
           Quarterly Report on Form 10-Q for the quarter ended June 30, 1996,
           filed August 14, 1996.)



                                       77
<PAGE>   78

10.27      Hedging Agreement between Chase and the Company dated June 1, 1996.
           (Incorporated by reference to Exhibit 10.31 to the Company's
           Quarterly Report on Form 10-Q for the quarter ended June 30, 1996,
           filed August 14, 1996.)

10.28      Purchase and Sale Agreement between the Company and Wattenberg Gas
           Investments, LLC dated April 25, 1996. (Incorporated by reference to
           Exhibit 10.32 to the Company's Quarterly Report on Form 10-Q for the
           quarter ended June 30, 1996, filed August 14, 1996.)

10.29      Purchase and Sale Agreement between Wattenberg Resources Land L.L.C.
           and Wattenberg Gas Investments, LLC dated May 21, 1996. (Incorporated
           by reference to Exhibit 10.33 to the Company's Quarterly Report on
           Form 10-Q for the quarter ended June 30, 1996, filed August 14,
           1996.)

10.30      Purchase and Sale Agreement between Orion and Wattenberg Gas
           Investments, LLC dated June 14, 1996. (Incorporated by reference to
           Exhibit 10.34 to the Company's Quarterly Report on Form 10-Q for the
           quarter ended June 30, 1996, filed August 14, 1996.)

10.31      Purchase and Sale Agreement between Wattenberg Resources Land L.L.C.
           and Wattenberg Gas Investments, LLC dated June 14, 1996.
           (Incorporated by reference to Exhibit 10.35 to the Company's
           Quarterly Report on Form 10-Q for the quarter ended June 30, 1996,
           filed August 14, 1996.)

10.32      Purchase and Sale Agreement between Orion and Wattenberg Gas
           Investments, LLC dated June 14, 1996. (Incorporated by reference to
           Exhibit 10.36 to the Company's Quarterly Report on Form 10-Q for the
           quarter ended June 30, 1996, filed August 14, 1996.)

10.33      Purchase and Sale Agreement between the Company and Wattenberg Gas
           Investments, LLC dated June 28, 1996. (Incorporated by reference to
           Exhibit 10.37 to the Company's Quarterly Report on Form 10-Q for the
           quarter ended June 30, 1996, filed August 14, 1996.)

10.34      Purchase and Sale Agreement between HSRTW, Inc. and WestTide
           Investments, LLC dated August 9, 1996. (Incorporated by reference to
           Exhibit 10.37 to the Company's Quarterly Report on Form 10-Q for the
           quarter ended September 30, 1996, filed November 7, 1996.)

10.35      Acquisition Agreement between the Company and TCW Portfolio No. 1555
           DR V Sub-Custody Partnership, L.P. dated August 30, 1996.
           (Incorporated by reference to Exhibit 10.38 to the Company's
           Quarterly Report on Form 10-Q for the quarter ended September 30,
           1996, filed November 7, 1996.)

10.36      Purchase Agreement dated November 27, 1996, among the Company, Orion,
           HSRTW, Inc., Salomon Brothers Inc., Chase Securities Inc., Lehman
           Brothers Inc., and Prudential Securities Incorporated. (Incorporated
           by reference to Exhibit 10.40 to the Company's Registration Statement
           on Form S-4, No 333-19433, filed January 8, 1997.)

10.37      Registration Agreement dated November 27, 1996, among the Company,
           Orion, HSRTW, Inc. and Salomon Brothers Inc. in its individual
           capacity and as agent for Chase Securities Inc., Lehman Brothers
           Inc., and Prudential Securities Incorporated. (Incorporated by
           reference to Exhibit 10.41 to the Company's Registration Statement on
           Form S-4, No 333-19433, filed January 8, 1997.)



                                       78
<PAGE>   79

10.38      Employment Agreement between James Piccone and the Company dated
           April 21, 1995. (Incorporated by reference to Exhibit 10.42 to the
           Company's Annual Report on Form 10-K for the fiscal year ended
           December 31, 1996, filed March 18, 1997 (as amended by Form 10-K/A-1
           on March 20, 1997.))

10.39      Purchase and Sale Agreement dated June 30, 1997 among HSRTW, Inc. and
           Horizon Gas Partners, L.P. as Seller and Gothic Energy Corporation as
           Buyer. (Incorporated by reference to Exhibit 10.43 to the Company's
           Quarterly Report on Form 10-Q for the quarter ended June 30, 1997,
           filed August 14, 1997.)

10.40      Amended Purchase and Sale Agreement dated as of July 16, 1997, among
           HSRTW, Inc. and Horizon Gas Partners, L.P. as Seller and Gothic
           Energy Corporation as Buyer. (Incorporated by reference to Exhibit
           10.44 to the Company's Quarterly Report on Form 10-Q for the quarter
           ended June 30, 1997, filed August 14, 1997.)

10.41      1997 Performance and Equity Incentive Plan. (Incorporated by
           reference to Exhibit A to the Company's Definitive Proxy Statement
           for its Annual Meeting of Stockholders held on May 22, 1997, filed
           April 24, 1997.)

10.42      Purchase and Sale Agreement between the Company and Amoco Production
           Company dated November 25, 1997. (Incorporated by reference to
           Exhibit 10.1 to the Company's Current Report on Form 8-K, filed
           December 23, 1997.)

10.43      Side Letter Agreement between the Company and Amoco Production
           Company dated November 25, 1997. (Incorporated by reference to
           Exhibit 10.2 to the Company's Current Report on Form 8-K, filed
           December 23, 1997.)

10.44      Closing Side Agreement between the Company and Amoco Production
           Company dated December 15, 1997. (Incorporated by reference to
           Exhibit 10.3 to the Company's Current Report on Form 8-K, filed
           December 23, 1997.)

10.45      Third Amendment to Amended and Restated Credit Agreement dated as of
           December 15, 1997, among the Company and The Chase Manhattan Bank as
           agent for the Lenders signatory thereto. (Incorporated by reference
           to Exhibit 10.4 to the Company's Current Report on Form 8-K, filed
           December 23, 1997.)

10.46*     Purchase and Sale Agreement dated December 15, 1997, by and between
           HS Resources, Inc. as Seller and WestTide Investments, LLC as Buyer.

23.1*      Consent of Arthur Andersen LLP

23.2*      Consent of Williamson Petroleum Consultants, Inc.

23.3*      Consent of Netherland, Sewell & Associates, Inc.

27*        Financial Data Schedule


-------------------------
*    Filed herewith




                                       79
<PAGE>   80
                                   SIGNATURES

          Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized, on this 31st day of March.

                                                HS RESOURCES, INC.

                                                By  /s/ Nicholas J. Sutton
                                                    ----------------------------
                                                    Nicholas J. Sutton
                                                    Chairman of the Board and
                                                    Chief Executive Officer


Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed by the following persons in the capacities indicated on this
31st day of March.

      Signature                                        Title
      ---------                                        -----

s/ Nicholas J. Sutton                       Chairman of the Board, Chief
---------------------------                      Executive Officer
 Nicholas J. Sutton                         (Principal Executive Officer)


/s/ P. Michael Highum                       President and Director
---------------------------
  P. Michael Highum


 /s/ James E. Duffy                           Chief Financial Officer
---------------------------                          and Director
   James E. Duffy                           (Principal Financial Officer)


 /s/ Annette Montoya                        Vice President - Accounting
---------------------------                         and Controller
   Annette Montoya                          (Principal Accounting Officer)


/s/ Kenneth A. Hersh                                  Director
---------------------------
  Kenneth A. Hersh


/s/ Michael J. Savage                                 Director
---------------------------
  Michael J. Savage


 /s/ Philip B. Smith                                  Director
---------------------------
   Philip B. Smith



                                       80
<PAGE>   81

                                 EXHIBIT INDEX


<TABLE>
<CAPTION>
   Exhibit
   Number       Description
   -------      -----------
   <S>          <C>
   10.46        Purchase and Sale Agreement dated December 15, 1997 by and
                between HS Resources, Inc. as Seller and WestTide Investments,
                LLC as Buyer.

   23.1         Consent of Arthur Andersen LLP

   23.2         Consent of Williamson Petroleum Consultants, Inc.

   23.3         Consent of Netherland, Sewell & Associates, Inc.

   27           Financial Data Schedule
</TABLE>





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